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Agenda Standards Committee January 16, 2013 | 8:00 a.m. – 5:00 p.m. ET January 17, 2013 | 8:00 a.m. – 3:00 p.m. ET NERC Headquarters 3353 Peachtree Road NE Suite 600, North Tower Atlanta, GA 30326 Phone Number: 1-866-740-1260 Meeting Code: 5247071 Security Code: 119832 Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Announcement* SC Expectations* Agenda Items 1. Review of Agenda(Approve) 2. Waiver of 5-day Rule(Approve) 3. Consent Agenda(Approve) a. December 13, 2012 Standards Committee Meeting Minutes*(Approve) b. January 7, 2013 Standards Committee Executive Committee Meeting Minutes*(Ratify) 4. Standards Committee Elections(Elect) a. Election of Officers* (Sent under separate cover) b. Election of At-Large Executive Committee Members* (To be sent separately) 5. Projects Under Active Development(Review) a. Status of Projects Under Active Development* b. Status of Outstanding Interpretations* c. Posting Projections Through February 2013*

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Agenda Standards Committee January 16, 2013 | 8:00 a.m. – 5:00 p.m. ET January 17, 2013 | 8:00 a.m. – 3:00 p.m. ET NERC Headquarters 3353 Peachtree Road NE Suite 600, North Tower Atlanta, GA 30326 Phone Number: 1-866-740-1260 Meeting Code: 5247071 Security Code: 119832 Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Announcement* SC Expectations* Agenda Items

1. Review of Agenda― (Approve)

2. Waiver of 5-day Rule― (Approve)

3. Consent Agenda― (Approve)

a. December 13, 2012 Standards Committee Meeting Minutes*― (Approve)

b. January 7, 2013 Standards Committee Executive Committee Meeting Minutes*― (Ratify)

4. Standards Committee Elections― (Elect)

a. Election of Officers* (Sent under separate cover)

b. Election of At-Large Executive Committee Members* (To be sent separately)

5. Projects Under Active Development― (Review)

a. Status of Projects Under Active Development*

b. Status of Outstanding Interpretations*

c. Posting Projections Through February 2013*

Standards Committee January 2013 Agenda 2

6. Actions

a. Strategic Plan, Work Plan, and Standards Committee Charter*― (Approve)

b. Plan for Five-Year Review* (L. Hussey)

i. Approach and Template― (Endorse)

ii. Solicit SME Nominations― (Approve)

c. Standards Authorization Requests

i. Standards Authorization Request to revise MOD-010 through MOD-015*― (Accept, Reject, or Remand) (B. Cummings)

ii. Supplemental Standards Authorization Request to revise PRC-023-2*― (Accept, Reject, or Remand) (H. Gugel)

iii. Supplemental Standards Authorization Request for Definition of BES Phase 2*― (Accept, Reject, or Remand) (L. Hussey and P. Heidrich)

7. Discussion Items

a. Report on Assessing the Need for Introducing Demand Response Functions and Entities to the NERC Reliability Functional Model* (B. Li)

b. WICF GOTO White Paper on Interconnection Facility* (M. Huggins)

c. Subcommittee Reports

i. Communication and Planning Subcommittee (A. Brown)

ii. Process Subcommittee (B. Li and L. Campbell)

8. Coordination― (Review) (S. Tyrewala)

a. Coordination with Regulatory and Governmental Authorities

b. Upcoming Standards Filings*

9. Informational Items― (Review)

a. Letter from RISC regarding GMD*

b. NERC Drafting Team Vacancies*

c. Standards Committee Roster*

d. Highlights of Parliamentary Procedure*

e. Schedule and Locations for 2013 Meetings*

Standards Committee January 2013 Agenda 3

10. Executive Committee Actions― (Pre-authorize)

a. Appoint SME Teams for Five-Year Review Projects

11. Adjourn

*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.

Public Announcements REMINDER FOR USE AT BEGINNING OF MEETINGS AND CONFERENCE CALLS THAT HAVE BEEN PUBLICLY NOTICED AND ARE OPEN TO THE PUBLIC Conference call version: Participants are reminded that this conference call is public. The access number was posted on the NERC website and widely distributed. Speakers on the call should keep in mind that the listening audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders.

Standards Committee Expectations Approved by Standards Committee January 12, 2012 Background Standards Committee (SC) members are elected by members of their segment of the Registered Ballot Body, to help the SC fulfill its purpose. According to the Standards Committee Charter, the SC’s purpose is:

In compliance with the NERC Reliability Standards Development Procedure, the Standards Committee manages the NERC standards development process for the North American-wide reliability standards with the support of the NERC staff to achieve broad bulk power system reliability goals for the industry. The Standards Committee protects the integrity and credibility of the standards development process.

The purpose of this document is to outline the key considerations that each member of the SC must make in fulfilling his or her duties. Each member is accountable to the members of the Segment that elected them, other members of the SC, and the NERC Board of Trustees for carrying out their responsibilities in accordance with this document. Expectations of Standards Committee Members 1. SC Members represent their segment, not their organization or personal views. Each member is

expected to identify and use mechanisms for being in contact with members of the segment in order to maintain a current perspective of the views, concerns, and input from that segment. NERC can provide mechanisms to support communications if an SC member requests such assistance.

2. SC Members base their decisions on what is best for reliability and must consider not only what is best for their segment, but also what is in the best interest of the broader industry and reliability.

3. SC Members should make every effort to attend scheduled meetings, and when not available are

required to identify and brief a proxy from the same segment. Standards Committee business cannot be conducted in the absence of a quorum, and it is essential that each Standards Committee make a commitment to being present.

4. SC Members should not leverage or attempt to leverage their position on the SC to influence the outcome of standards projects.

5. The role of the Standards Committee is to manage the standards process and the quality of the output, not the technical content of standards.

Draft Minutes Standards Committee December 13, 2012 | 1:00 p.m. – 5:00 p.m. ET Administrative Items

Chairman Mosher welcomed committee members and observers and determined the presence of a quorum. The attendance of Standards Committee members is provided in Attachment A.

Kristin Iwanechko reviewed the NERC Antitrust Compliance Guidelines and reminded participants that notice of the conference call had been widely distributed. Chairman Mosher also reminded SC members that the SC Expectations had been provided in their meeting materials. Agenda

1. Review of Agenda

Committee members made several revisions to the agenda. A revised agenda is included as Attachment B.

2. Waiver of 5-day Rule

F. Plett motioned to approve the agenda as modified and waive the 5-day rule.

- The Committee approved the motion without objection or abstention.

3. Consent Agenda

a. October 4, 2012 Standards Committee’s Executive Committee Meeting Minutes

b. November 8, 2012 Standards Committee Meeting Minutes

c. November 19, 2012 Standards Committee’s Executive Committee Meeting Minutes

S. Miller motioned to approve the consent agenda.

- The Committee approved the motion without objection or abstention.

4. Projects under Active Development

a. Status of Projects Under Active Development

• Update on Project 2010-17 Definition of BES

Pete Heidrich, chair of the Definition of Bulk Electric System, reported that the Planning Committee had reviewed a report that was prepared at the request of the drafting team, and had decided to defer action on the report until January 2013, pending revisions to

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Standards Committee December 2012 Draft Minutes 2

finalize the report. Depending on the nature of the changes and how substantive they are, Mr. Heidrich reported that the posting of the Phase 2 definition for a 45-day comment period and initial ballot may slip beyond the planned March timeframe.

• Update on Project 2010-14.1 BARC Phase 1

A. Ireland reported that she talked to drafting team members about stakeholder concerns regarding the reliability benefit of BAL-012-1. It was noted that there are outstanding FERC directives on this project and NERC Legal is reviewing the directives. Committee members discussed that this type of issue could be delegated to Project Management and Oversight Subcommittee (PMOS) when formed.

• Update on Project 2007-09 Generator Verification

A. Ireland attended the recent Project 2007-09 standard drafting team meeting and provided a report on her observations.

b. Status of Outstanding Interpretations

No questions were raised by Committee members on this item.

c. Posting Projections Through January 2013

No questions were raised by Committee members on this item.

5. Actions

a. Reliability Standards Development Plan

M. Lauby and A. Mosher presented the Reliability Standards Development Plan (RSDP) to the Standards Committee. M. Lauby noted that, under the section on Integration of Internal Controls with Standards on page 9 of the RSDP, the second paragraph and the first sentence of the first paragraph would be removed and some minor editorial changes would be made.

F. Plett motioned to approve the RSDP with the revisions described.

- The Committee approved the motion without objection or abstention.

b. Project 2010-16 Definition of System Operator – Solicit Nominations

H. Gugel reported Project 2010-16 is scheduled for 2013 and that the Standard Authorization Request for Project 2010-16 was posted for comment in 2010, but standard drafting team nominations were never solicited.

J. Bussman motioned to approve soliciting standard drafting team nominations for Project 2010-16.

- The Committee approved the motion without objection or abstention.

6. Discussion Items

a. Update on Draft Strategic Plan, Work Plan, and Charter Changes

M. Lauby thanked volunteers for working with NERC staff on the strategic plan, work plan, and charter changes. Mr. Lauby noted that the draft Strategic Plan and draft Work

Standards Committee December 2012 Draft Minutes 3

Plan were provided to solicit comments and thoughts from SC members and a meeting would be scheduled on January 7th and 8th

NERC Trustee Ken Peterson commented that good progress was being made with the draft strategic plan, work plan, and charter changes.

to finalize the documents. M. Lauby also reported that NERC General Counsel is reviewing areas that need to be consistent across all charters and the draft Standards Committee charter changes would be sent to Standards Committee members for comment after review by NERC General Counsel and the ad hoc group.

b. Update on Revisions to Outstanding VRFs/VSLs Project and Schedule

M. Huggins reported that the final revisions would be presented to the NERC Board of Trustees for approval on its December conference call and will be filed with regulatory authorities.

c. Modification of Glossary Term “Area Control Error” for WECC Regional Variance

H. Gugel reported that in its posting of WECC Regional Variance BAL-001-1, WECC entities approved a new definition for Automatic Time Error Correction and a modification to the definition of Area Control Error, which only affect the WECC entities, during their ballot of BAL-001-1. Mr. Gugel noted that BAL-001-1 was going to the NERC Board of Trustees for approval in December and requested that the Committee determine whether the glossary terms need a continent-wide ballot.

F. Plett motioned to submit the revised definitions to the NERC Board of Trustees as written without a continent-wide ballot.

- The Committee approved the motion without objection and two abstentions (S. Rueckert and S. Myers).

d. Process for Standards Committee Intervention for Standards Not Reaching Consensus After Repeated Successive Ballots

J. Bussman asked for a discussion to address this issue. The Committee discussed the issue, but did not reach a resolution.

e. Subcommittee Reports

1. Communication and Planning Subcommittee

Chair Anne Brown and NERC Staff Coordinator Mallory Huggins reported that during the SCCPS’s December 11, 2013 conference call, the Subcommittee focused on plans for its January meeting, during which it plans to develop a charter, determine whether the role of the SCCPS needs to change to accommodate other changes within the Standards Committee and the standards department, and discuss whether the current membership needs to grow or change at all. The Subcommittee also reported on its continuing work on a communication plan template to be used for standards development projects, including the Rapid Revision and GMD plans already under development.

2. Process Subcommittee

Standards Committee December 2012 Draft Minutes 4

L. Campbell reported that the Process Subcommittee has been working primarily on the revisions to the NERC Standard Processes Manual. She noted that a webinar was held and the revisions were posted for comment and an initial ballot through December 20, 2012. Between the December and January Standards Committee Meetings, the Process Subcommittee will be focusing on responding to comments received from the comment period.

3. Nominating Committee

F. Plett reported that a reminder was sent to the Standards Committee that nominations are due by December 15, 2012. After nominations are received, the Nominating Committee will disseminate the nominations to the Standards Committee for consideration.

Clarification was also given that the Nominating Committee is seeking a chair and vice chair for a one-year term to fill the remainder of Chairman Mosher’s term.

7. Coordination

a. Coordination with Regulatory and Governmental Authorities

b. Upcoming Standards Filings

S. Tyrewala reported on the upcoming standards filings included in the agenda and noted that the CIP Version 5 filing was projected to be filed at the end of January 2013.

8. Informational Items

a. NERC Drafting Team Vacancies

b. Standards Committee Roster

c. Highlights of Parliamentary Procedure

d. Schedule and Locations for 2013 Meetings

K. Iwanechko noted that the August 2013 conference call was rescheduled to avoid a conflict with the NERC Board of Trustees meeting.

9. Executive Committee Actions

S. Miller motioned that the Standards Committee authorize its Executive Committee to vote on authorizing posting BAL-001-1, BAL-002-2, and BAL-013-1 for a 45-day formal comment period with the formation of a ballot pool during the first 30 days and an initial ballot during the last 10 days of that 45-day comment period.

S. Miller also motioned to pre-authorize the EC to act on a Standard Authorization Request on GMD, if one was submitted.

- The Committee approved both motions without objection or abstention.

10. Adjourn

*Background materials included.

Page 1 of 2

Standards Committee December 13, 2012 Attendance List

Segment Name Company Attendance

Chairman Allen Mosher American Public Power Association x

Vice Chairman P.S. (Ben) Li Ben Li Associates, Inc.

Segment 1-2011-12 Jason Shaver American Transmission Company, LLC x

Segment 1-2012-13 Carol Sedewitz National Grid x

Segment 2-2011-12 Al DiCaprio PJM x

Segment 2-2012-13 H. Steven Myers ERCOT x

Segment 3-2011-12 Ronald G. Parsons Alabama Power Company x

Segment 3-2012-13 John Bussman Associated Electric Cooperative Inc. x

Segment 4-2011-12 Joseph Tarantino Sacramento Municipal Utility District x

Segment 4-2012-13 Frank Gaffney Florida Municipal Power Authority x

Segment 5-2011-12 Gary Kruempel MidAmerican Energy Company x

Segment 5-2012-13 Scott Miller MEAG Power x

Segment 6-2011-12 Silvia Parada Mitchell

Brian Murphy, proxy NextEra Energy, Inc. x

Segment 6-2012-13 Alice Murdock Ireland Xcel Energy, Inc. x

Segment 7-2011-12 John A. Anderson Electricity Consumers Resource Council

Segment 7-2012-13 Frank McElvain Siemens Energy

Segment 8-2011-12 Michael Goggin American Wind Energy Association

Segment 8-2012-13 Fred Plett Massachusetts Attorney General x

Segment 9-2011-12 Diane Barney New York State Public Service Commission x

Segment 9-2012-13 Klaus Lambeck Ohio Public Utilities Commission x

Attachment A

Page 2 of 2

Segment Name Company Attendance

Segment 10-2011-12 Steve Rueckert Western Electricity Coordinating Council x

Segment 10-2012-13 Linda Campbell Florida Reliability Coordinating Council x

Canada David Kiguel Hydro One Networks Inc. x

Secretary Laura Hussey NERC x

BOT Members: • Ken Peterson

FERC Staff: • Tom Bradish

NERC Staff:

• Mark Lauby • Howard Gugel • Valerie Agnew • Kristin Iwanechko • Holly Hawkins • Stacey Tyrewala • Mark Olson

• Steve Crutchfield • Erika Chanzes • Edd Dobrowolski • Mallory Huggins • Dave Taylor

A number of observers also attended the call.

Draft Agenda Standards Committee December 13, 2012 | 1:00 p.m. – 5:00 p.m. ET Phone Number: 1-866-740-1260 Meeting Code: 5247071 Security Code: 1234321 Introductions and Chair’s Remarks

NERC Antitrust Compliance Guidelines *

Public Announcement *

SC Expectations *

Agenda

1. Review of Agenda (Approve)

2. Waiver of 5-day Rule (Approve)

3. Consent Agenda (Approve)

a. October 4, 2012 Standards Committee’s Executive Committee Meeting Minutes* (Ratify)

b. November 8, 2012 Standards Committee Meeting Minutes* (Approve)

c. November 19, 2012 Standards Committee’s Executive Committee Meeting Minutes* (Ratify)

4. Projects under Active Development (Review)

a. Status of Projects Under Active Development*

• Update on Project 2010-17 Definition of BES (P. Heidrich)

• Update on Project 2010-14.1 Phase 1 (A. Ireland)

• Update on Project 2007-09 Generator Verification (A. Ireland)

b. Status of Outstanding Interpretations*

c. Posting Projections Through January 2013* (K. Iwanechko)

5. Actions

a. Reliability Standards Development Plan* (Approve)

Attachment B

Standards Committee December 2012 Agenda 2

b. Project 2010-16 Definition of System Operator – Solicit Nominations (H. Gugel) (Authorize)

6. Discussion Items

a. Update on Draft Strategic Plan, Work Plan, and Charter Changes* (M. Lauby, A. Mosher) (Discuss/Request Comments - to be sent separately)

b. Update on Revisions to Outstanding VRFs/VSLs Project and Schedule* (M. Huggins)

c. Modification of Glossary Term “Area Control Error” for WECC Regional Variance* (H. Gugel)

c.d. Process for Standards Committee Intervention for Standards Not Reaching Consensus After Repeated Successive Ballots (J. Bussman)

d.e. Subcommittee Reports

1. Communication and Planning Subcommittee (A. Brown)

2. Process Subcommittee (B. Li and L. Campbell)

2.3. Nominating Committee (F. Plett and C. Sedewitz)

7. Coordination (Review) (S. Tyrewala)

a. Coordination with Regulatory and Governmental Authorities

b. Upcoming Standards Filings*

8. Informational Items (Review)

a. NERC Drafting Team Vacancies*

b. Standards Committee Roster*

c. Highlights of Parliamentary Procedure*

d. Schedule and Locations for 2013 Meetings*

9. Executive Committee Actions (Pre-authorize)

10. Adjourn

*Background materials included.

Draft Meeting Minutes Standards Committee Executive Committee January 7, 2013 | 12:00 p.m. ET Administrative

Chairman Mosher welcomed executive committee members and observers and determined the presence of a quorum. Ms. Kristin Iwanechko reviewed the NERC Antitrust Guidelines and reminded participants that notice of the conference call had been widely distributed.

The following Executive Committee members were present:

• Allen Mosher • Ben Li • John Bussman • David Kiguel

There were also a number of Standards Committee members and NERC Staff on the call. Agenda Items

1. Project 2010-14.1 – Phase 1 of Balancing Authority Reliability-based Controls: Reserves – BAL-001-1, BAL-002-2, BAL-013-1

J. Bussman motioned to authorize posting BAL-001-1, BAL-002-2, and BAL-013-1 for a 45-day formal comment period with the formation of a ballot pool during the first 30 days and an initial ballot during the last 10 days of that 45-day comment period.

- The motion was approved without objection or abstention.

2. Adjourn

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S - SC Project Step (Multi-Row)

Name

Program: Standards Development(19)

Priority: Normal(11)

Project 2006-06 Reliability CoordinationDescription:To ensure that the reliability-relatedrequirements applicable to the Reliability Coordinatorare clear, measurable, unique and enforceable; andto ensure that this set of requirements is sufficient tomaintain reliability of the Bulk Electric System.

Leadership:Mike Hardy (SoCo)NERC Staff:Scott Barfield-McGinnisSAR Date:12/16/06Team Assembly:6/5/07Target Finish:1/14/13Forecast Finish:2/13/13SPM Step:FilingRelated Standards:IRO-001 - Reliability Coordination -Responsibilities and Authorities, COM-002 -Communication and Coordination, IRO-003 - ReliabilityCoordination - Wide-Area View, IRO-005 - ReliabilityCoordination - Current Day Operations, IRO-015 -fications and Information Exchange Between ReliabilityCoordinators, COM-001 - Telecommunications, IRO-002 -Reliability Coordination - Analysis Tools, IRO-014 -Coordination Among Reliability Coordinators, IRO-016 -Coordination of Real-time Activities Between ReliabilityCoordinatorsLast Update:1/7/13

Status:NERC Legal is working on the draft petition.

The remaining standard for this project is IRO-003-2, whichthe drafting team tabled in early January 2012 to focus onmoving the other standards forward. As part of the 2013-2015 Reliability Standards Development Plan, this standardwill be reviewed as part of a comprehensive review of the IROfamily of standards to ensure that NERC is current on 5-yearreviews and has met outstanding FERC directives.

Project 2007-03: Real-time Operations r0Description:Clarify requirements for real-timeoperations of the Bulk Electric System in the citedstandards. Consider stakeholder comments receivedduring the initial development of the standards andother comments received from ERO and regulatoryauthorities

Leadership:Jim Case, EntergyNERC Staff:Edward DobrowolskiSAR Date:4/16/07Team Assembly:12/11/07Target Finish:10/23/12Forecast Finish:2/12/13SPM Step:FilingRelated Standards:PER-001 - Operating PersonnelResponsibility and Authority, TOP-002 - OperationsPlanning, TOP-004 - Transmission Operations, TOP-007 -Reporting System Operating Limit (SOL) andInterconnection Reliability Operating Limit (IROL)Violations, TOP-003 - Operational Reliability Data, TOP-008 - Response to Transmission Limit Violations, TOP-001 - Transmission Operations, TOP-005 - OperationalReliability Information, TOP-006 - Monitoring SystemConditionsLast Update:12/4/12

Status:NERC Legal is working on the draft petition.

S - SC Project Step (Multi-Row) Page 1 1/9/13 12:02 PM

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Project 2007-09 Generator VerificationDescription:Requires upgrading existingrequirements for generators to verify theircapabilities to ensure that accurate data is used inmodel to assess the bulk electric system.

Leadership:Lee TaylorKen StenroosDave KralNERC Staff:Stephen CrutchfieldSAR Date:4/3/07Team Assembly:9/12/07Target Finish:10/19/12Forecast Finish:3/4/13SPM Step:Recirculation BallotRelated Standards:PRC-024 - Generator PerformanceDuring Frequency and Voltage Excurs ions, PRC-019 -Coordination of Generating Unit or Plant Capabilities,Voltage Regulating Controls, and Protection, MOD-026 -Verification of Models and Data for Generator ExcitationControl Sys tem Functions and Plant Volt/Var ControlFunctions, MOD-027 - Verification of Models and Datafor Turbine/Governor and Load Control or ActivePower/Frequency Control Functions, MOD-025 -Verification and Data Reporting of Generator Real andReactive Power Capability and Synchronous Condens erReactive Power Capability, MOD-024 - Verification ofGenerator Gross and Net Real Power CapabilityLast Update:1/9/13

Status:MOD-025, MOD-027 and PRC-019: The standards wereposted for a 45-day formal comment period and concurrentinitial ballot period from February 29 through April 16. Theteam met May 15-17 and developed responses to commentsand revisions to the standards. The team worked with QR torespond to their comments and re-submitted the documentsJuly 26. The posting schedule was determined during theAugust 9, 2012 SC meeting for this project. The standardswere posted for a formal comment period and successiveballot, which ended on October 31, 2012. Each standardachieved a qurorum and passed the ballot. The teamcompleted responses to comments and the standards wereposted for a recirculation ballot on December 12 throughDecember 21. The standards passed the ballot.

MOD-026 and PRC-024: The standards were posted for a 30day formal comment period and successive ballot betweenFebruary 29th and March 29th. The team met May 15-17 anddeveloped responses to comments and revisions to thestandards. The team worked with QR to respond to theircomments and re-submitted the documents July 26. Theposting schedule was determined during the August 9, 2012SC meeting for this project. The standards were posted for aformal comment period and successive ballot, which ended onOctober 31, 2012. MOD-026 failed to reach a quorum, so theballot was extended. MOD-026 passed the ballot, but PRC-024 failed. The team completed response to comments andMOD-026 was posted for recirculation ballot December 12-21and PRC-024 was posted for a successive ballot / 30 daycomment period December 12 - January 11. MOD-026 passedthe recirculation ballot.

A coordination issue with RFC standards MOD-024 and MOD-025 is being addressed. RFC is withholding filing of their MOD-024 and MOD-025 standards until the continent-widestandard MOD-025 is approved. They will then evaluatewhether the continent-wide standard meets their needs.

Project 2010-07: Generator Requirements at theTransmission InterfaceDescription:The proposed changes to therequirements and the addition of new requirementswill add significant clarity to Generator Owners andGenerator Operators regarding their reliabilitystandard obligations at the interface with theinterconnected grid.

Leadership:Louis Slade (Dominion)NERC Staff:Mallory HugginsSAR Date:1/15/10Team Assembly:6/16/10Target Finish:1/25/13Forecast Finish:1/9/13SPM Step:CompletedRelated Standards:PRC-005 - Transmission andGeneration Protection System Maintenance and Testing,FAC-001 - Facility Connection Requirements, PRC-004 -Analysis and Mitigation of Transmission and GenerationProtection System Misoperations, FAC-003 -Transmission Vegetation ManagementLast Update:11/30/12

Status:FAC-001-1 and PRC-004-2.1a were adopted by the BOTon February 9, 2012. PRC-005-1.1b and FAC-003-3 wereadopted by the BOT on May 9, 2012. The legal petition, whichincorporated all of the standards, was filed with FERC on July30, 2012.

S - SC Project Step (Multi-Row) Page 2 1/9/13 12:02 PM

Name

Project 2010-13.2 Generator Relay LoadabilityDescription:Project 2010-13 Relay Loadability Orderinvolves a new standard PRC-025-1 Generator RelayLoadability standard and maybe other standards incompliance with the FERC Order 733 issued on March18, 2010.

Leadership:Charlie Rogers (Consumers Energy)NERC Staff:Scott Barfield-McGinnisSAR Date:Team Assembly:Target Finish:9/30/13Forecast Finish:2/6/14SPM Step:Responding to CommentsRelated Standards:PRC-025 - Generator RelayLoadabilityLast Update:1/7/13

Status:The project is 19 weeks behind its planned deliverybecause the draft standard during its informal developmentdid not meet the results-based standard (RBS) criteria; andduring the rewrite, the team determined additional technicalanalysis was necessary to improve the clarity of the requiredperformance that would have been revealed by industrystakeholders, resulting in additional schedule slide. The teamis working diligently to compress the schedule as much aspossible and will assess the feasibility of achieving the filingdeadline (September 30, 2013) following the initial ballotposting in early 2013. Preemptively, the team held a secondmeeting December 11-14 2012 in Atlanta primarily tocontinue addressing stakeholder comments and secondarilyfor other components of the project, such as, VSLjustifications, RSAW development, and mitigation of identifiedrisks to the project revealed in the comments or by the team.

Project 2010-17 Definition of BES Phase 2Description:Investigate threshold limits and clarifyitems from Phase 1.

Leadership:Pete Heidrich, FRCC, ChairBarry Lawson, NRECA, Vice ChairNERC Staff:Edward DobrowolskiSAR Date:12/2/11Team Assembly:4/11/12Target Finish:11/13/13Forecast Finish:1/24/14SPM Step:DraftingRelated Standards:Last Update:1/7/13

Status:Phase 2 is well underway. The Planning Committee istaking the lead on investigating threshold limits. The PC wasgiven a deadline of December 20, 2012 for the completion ofits work which it did not meet. There is no definite date forthe receipt of the PC report but a summary ofrecommendations has been provided.

FERC issued Order 773 on December 20, 2012 accepting thePhase 1 definition with several directives. The window forrequesting clarifications and/or rehearing is still open at thistime.

Project 2010-INT-01 Interpretation of TOP-006-2 forFMPPDescription:Florida Municipal Power Pool (FMPP) isseeking clarification as to whether the BalancingAuthority is responsible for reporting generationresources available for use and the TransmissionOperator is responsible for reporting transmissionresources that are available for use. They are alsoseeking clarification as to whether “appropriatetechnical information concerning protective relays”refers to protective relays for which the entity hasresponsibility.

Leadership:NERC Staff:Edward DobrowolskiSAR Date:Team Assembly:Target Finish:Forecast Finish:1/31/13SPM Step:Board ReviewRelated Standards:TOP-006 - Monitoring SystemConditionsLast Update:12/4/12

Status:BOT adopted at the November 2012 meeting. It shouldbe filed shortly.

Project 2011-INT-01 Interpretation of MOD-028 forFlorida Power & Light CompanyDescription:By using the words “on-peak”, “off-peak”, and “intra-day” this requirement implies therewould have to be separate TTC numbers for differentportions of the current day. However, R5 of MOD28establishes the calculation frequencies and onlyrequires an update to TTC once within the 7 daysprior to the specified period where they are used inan ATC calculation. The clarification needed is on theATC Drafting Team’s intent with respect to thequantity and timing of individual TTC calculationsneeded for use in the ATC calculations.

Leadership:NERC Staff:Valerie AgnewSAR Date:Team Assembly:Target Finish:Forecast Finish:9/7/12SPM Step:CompletedRelated Standards:MOD-028 - Area InterchangeMethodologyLast Update:9/7/12

Status:Rapid Revision PilotApproved at the February Board of Trustees meeting. Filedwith FERC on 8/24/2012.

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Project 2011-INT-02 Interpretation of VAR-002 forConstellation Power GenDescription:Asks for clarification of whether a GOPmust communicate to a TOP that a generator is inmanual mode (no AVR) during start up or shut down.

Leadership:NERC Staff:Stephen CrutchfieldSAR Date:Team Assembly:Target Finish:Forecast Finish:11/21/12SPM Step:CompletedRelated Standards:VAR-002 - Generator Operation forMaintaining Network Voltage SchedulesLast Update:12/20/12

Status:This Interpretation Request was approved by the SC forRapid Revision on Jan 12, 2012. The team held twoconference calls the week of April 9-13 to discuss commentsreceived and determine the next step for the standard. Theteam has completed developing responses to comments andmade conforming revisions to the standard for QR on April 26.The documents were submitted to QR on April 30. The teamreceived feedback from QR and made appropriate revisions tothe documents and resubmitted them for posting on May 15.

The draft standard was posted for a 30-day successive ballotand comment period on May 22; and due to a technical issuethe posting was extended to June 27. The standard achieveda quorum and passed the successive ballot.

The team held a conference call on July 2 to discuss thecomments received on the ballot and prepare for therecirculation ballot. The team developed responses tocomments and revised the VSLs for Requirement R2. TheConsideration of Comments and revised standard weresubmitted July 9 for posting. The standard was posted forrecirculation from July 18 to July 27 and received enoughsupport to pass the ballot.

The proposed standard was presented to the NERC BOT at theAugust 16th meeting and approved. NERC Legal staffsubmitted the regulatory filing to FERC on November 21st.

Project 2012-08.1 Glossary Updates Phase1:Statutory DefinitionsDescription:The purpose of this project is to add thestatutory definitions for Bulk Power System, ReliableOperation, and Reliability Standard to the Glossary ofTerms Used in Reliability Standards pursuant to threedirectives issued by the the Federal EnergyRegulatory Commission (FERC) in FERC Order 693.

Leadership:An industry chair has not been assigned tothis project as of yet.NERC Staff:David TaylorSAR Date:3/15/12Team Assembly:Target Finish:12/31/12Forecast Finish:8/15/13SPM Step:Successive BallotRelated Standards:A_DEFINITION_ONLYLast Update:10/26/12

Status:The SAR for adding the definitions for Bulk PowerSystem, Reliable Operation, and Reliability Standard to theGlossary of Terms Used in Reliability Standards was posted fora 45-day formal comment period from June 19 through August2, 2012. An initial ballot was conducted July 24 throughAugust 2, 2012.

The weighted sector vote for the initial ballot was 54%.Responses to the comments received are currently beingdeveloped. No timetable has been established for moving to asuccessive ballot.

Project 2013-02: Paragraph 81Description:Retire or modify Reliability Standardrequirements that as FERC noted, "provide littleprotection to the reliable operations of the BES," areredundant or unnecessary, or to retire or modify aReliability Standard requirement to increase theefficiency of the ERO's compliance programs. Phase1 of the project identifies Reliability Standardrequirements that clearly meet the criteria set forthin the SAR and do not require extensive technicalresearch.

Leadership:Brian Murphy (Next Era) - Chair, Guy Zito(NPCC) - Vice ChairNERC Staff:Kristin IwanechkoSAR Date:7/10/12Team Assembly:Target Finish:Forecast Finish:3/31/13SPM Step:Initial BallotRelated Standards:Last Update:12/4/12

Status:On October 25, 2012, the requirements being proposedfor retirement (38 requirements in 22 standard versions) andan implementation plan were posted for a formal commentperiod and an initial ballot that will end on Monday, December10, 2012 (the initial ballot will begin on Friday, November 30,2012).

Priority: High(8)

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Project 2007-02 Operating Personnel CommunicationProtocolsDescription:Requires developing new requirements insupport of blackout recommendation #26 to ensurethat real-time system operators use standardcommunication protocols during normal andemergency operations.

Leadership:Lloyd SnyderNERC Staff:Joseph KrisiakSAR Date:3/1/07Team Assembly:9/9/11Target Finish:5/15/13Forecast Finish:7/16/13SPM Step:Successive BallotRelated Standards:BAL-002-WECC - ContingencyReserve (WECC)Last Update:1/8/13

Status:Draft 4 of COM-003-1 did not achieve industry approval(53%) od its second successive 30 day comment period and10 day concurrent ballot (commencing December 04, 2012)ending December 13, 2012.

The SDT is considering and responding to industry comments;and is developing draft 5 of the standard for a third successiveballot. The OPCPSDT is also proposing a techical conferencefor February 14 to 15, 2013 to discuss industry concerns.

Project 2007-06 System Protection CoordinationDescription:Address applicability issues and upgradeexisting requirements to remove ambiguity, andensure that there is coordination of protection andcontrol systems that connect more than onefunctional entity.

Leadership:Philip Winston, Southern CompanyNERC Staff:Al McMeekinSAR Date:5/7/07Team Assembly:10/11/07Target Finish:1/21/13Forecast Finish:9/16/13SPM Step:Responding to CommentsRelated Standards:PRC-001 - System ProtectionCoordinationLast Update:1/7/13

Status:The comment report from the 2nd posting of the draftstandard was distributed to the team and responses to thecomments are being developed.

NOTE: The SC agreed the delay associated with the QR andresults-based feedback is acceptable, but did not want toreforecast completion. The project will continue to bereported as behind schedule, with the understanding that thisis an acceptable delay.

Project 2007-12 Frequency ResponseDescription:Project 2007-12 Frequency Response andFrequency Bias - Develop a minimum FrequencyResponse needed for reliable operation and aconsistent method for calculating the Frequency BiasSetting.

Leadership:Dave Lemmons - Xcel - ChairTerry Bilke - MISO - VicechairNERC Staff:Darrel RichardsonSAR Date:4/7/04Team Assembly:8/13/07Target Finish:3/19/13Forecast Finish:2/22/13SPM Step:Board ReviewRelated Standards:BAL-003 - Frequency Response andBiasLast Update:1/4/13

Status:NERC filed for an extension of time to complete theproposed standard. FERC responded granting an extension ofone year (filing deadline - May 31, 2013).

NERC held two technical conferences on Frequency Responseand collected technical comments and opinions on relevantissues. NERC filed a second progress report at FERC on thisstandard on October 31, 2012. The SDT has prepared a thirddraft of the standard and associated documents for postingand a successive ballot. The draft standard and associateddocuments was posted for a 30-day comment period andsuccessive ballot on October 5, 2012. The comment periodand successive ballot ended on November 5, 2012. Theproposed standard passed with a quorum of 82.04% and aindustry approval of 76.30%. The draft standard andassociated documents were posted for a re-circulation ballotfrom December 12, 2012 through December 21, 2012. Thedraft standard passed the re-circulation ballot with a quorumof 86.19% and a industry approval of 76.53%.

The draft standard will be presented to the NERC BOT at theirFebruary meeting for adoption.

This project is being coordinated with Project 2010-14.1Balancing Authority Reliability-Based Controls-Reserves forthe BAL-012 standard.

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Project 2007-17 Protection System Maintenance andTestingDescription:Transmission and Generation ProtectionSystem Maintenance and Testing, to consolidate PRC-005-1, PRC-008-0 — Underfrequency Load SheddingEquipment Maintenance Programs; PRC-011-0 —UVLS System Maintenance and Testing; and PRC-017-0 — Special Protection System Maintenance andTesting into a single maintenance and testingstandard. Standards PRC-008-0, PRC-011-0, and PRC-017-0 would then be withdrawn.

Leadership:Charles W. Rogers, Consumers EnergyNERC Staff:Al McMeekinSAR Date:5/7/07Team Assembly:10/11/07Target Finish:11/21/12Forecast Finish:1/10/13SPM Step:FilingRelated Standards:PRC-011 - Undervoltage LoadShedding System Maintenance and Testing, PRC-005 -Transmission and Generation Protection SystemMaintenance and Testing, PRC-017 - Special ProtectionSystem Maintenance and Testing, PRC-008 -Implementation and Documentation of UnderfrequencyLoad Shedding Equipment Maintenance ProgramLast Update:1/9/13

Status:The BOT approved PRC-005-2 at their November boardmeeting. The initial FERC filing documents were prepared andsent to NERC management and legal staff. NERC legal and thestandards developer are drafting the petition.

Project 2007-17 Phase 2: (Reclosers) will address themaintenance of reclosing relays which can affect the reliableoperation of the Bulk Electric System. The SDT is providing aSAR to the SC (January,'13) to modify PRC-005-2 toaccomplish this and present PRC-005-3 to the BOT in the 3rdqtr. of 2013.

NERC has initiated the process of gathering data pertinent toreclosing and auxiliary relays that is necessary to developrequirements for the maintenance of those relays.FERC issued Order 758 (February 3, 2012) approving a NERCInterpretation on PRC-005-1 and further directed NERC toinclude reclosing relays as well as auxiliary and non-electricalsensing relays (including sudden pressure relays).•NERC believes it is on track to meet all outstandingdirectives associated with PRC-005, including thoseemanating from Order 758.•NERC submitted two informational filings to FERC in responseto Order 758.•NERC drafted a SAR to add the maintenance and testing ofreclosing relays in version PRC-005-3 which will beginimmediately after PRC-005-2 is BOT approved.•NERC submitted a schedule to include sudden pressurerelays (used in taking transformers out of service) and otherauxiliary relays in PRC-005-4 beginning in 2014.

Project 2008-06 Cyber Security Order 706Description:The second phase (Phase 2) of Project2008-06 Cyber Security Order 706 will require theSDT to propose modifications not included in Phase 1of the project to bring the following standards intoconformance with the ERO Rules of Procedure and toaddress the directives from FERC Order 706:CIP-002-2 Critical Cyber Asset IdentificationCIP-003-2 Security Management ControlsCIP-004-2 Personnel & TrainingCIP-005-2 Electronic Security Perimeter(s)CIP-006-2 Physical Security of Critical Cyber AssetsCIP-007-2 Systems Security ManagementCIP-008-2 Incident Reporting and Response PlanningCIP-009-2 Recovery Plans for Critical Cyber Assets

Leadership:John Lim (Consolidated Edison Co. of NewYork)

Philip Huff (Arkansas Electric Cooperative Corporation)NERC Staff:Steven NoessSAR Date:3/1/08Team Assembly:8/8/08Target Finish:8/4/12Forecast Finish:2/27/13SPM Step:FilingRelated Standards:CIP-011 - Cyber Security —Information Protection, CIP-008 - Cyber Security —Incident Reporting and Response Planning, CIP-004 -Cyber Security – Personnel & Training, CIP-010 - CyberSecurity — Configuration Management and VulnerabilityAssessments, CIP-005 - Cyber Security – ElectronicSecurity Perimeter(s), CIP-003 - Cyber Security —Security Management Controls, CIP-009 - Cyber Security— Recovery Plans for BES Cyber Systems April 10, 2012Standard Development, CIP-007 - Cyber Security –Systems Security Management, CIP-002 - CyberSecurity — BES Cyber Asset and BES Cyber SystemCategorization, CIP-006 - Cyber Security — PhysicalSecurity of BES Cyber SystemsLast Update:1/8/13

Status:The NERC Board of Trustees approved CIP Version 5 onNovember 26, 2012, and it is being prepared for filing.

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Project 2009-01 Disturbance and Sabotage ReportingDescription:Project 2009-01 Disturbance andSabotage Reporting - This project will entail revisionto the following existing standards:•CIP-001-1 – Sabotage Reporting•EOP-004-1 – Disturbance Reporting

This Standard is intended to assure that informationon activities related to disturbances or unusualoccurrences, potentially impacting or jeopardizingthe BPS are shared and properly reported amongother system operators as well as governmentalbodies.

Leadership:Chair - Brian Evans-Mongeon (Util. Svcs.)Vice-Chair - Joseph DePoorter (MGE)NERC Staff:Stephen CrutchfieldSAR Date:4/2/09Team Assembly:11/12/09Target Finish:9/9/12Forecast Finish:12/31/12SPM Step:CompletedRelated Standards:CIP-008 - Cyber Security — IncidentReporting and Response Planning, EOP-004 -Disturbance Reporting, CIP-001 - Sabotage ReportingLast Update:1/7/13

Status:The standard was posted for a 30-day comment periodand successive ballot which ended on May 24, 2012. Theteam met June 6-8 and began to respond to comments andrevise the standard. The team conducted stakeholderoutreach to help the standard achieve a successful ballot.The team held an industry webinar July 30, 2012 and then ateam meeting to finalize all documents for posting andsuccessive ballot. The team submited the documents for QRon August 3, 2012 and ireceiverd the results on August 15th.The team responded to the comments received from QR onAugust 23.

The standard was posted for successive ballot that ended onSeptember 27th with a 63.40% approval rating. The teammet October 4-5 to discuss the comments received and nextsteps. The team will proceed to recirculation ballot and heldan industry webinar on October 22. The recirculation ballotbegan on October 24th and was extended until November 5thdue to issues arising from "Superstorm Sandy". The standardpassed the recirculation abllot and was approved by the NERCBOT on November 7th. The Standards Coordinator is workingwith NERC legal staff to develop the regulatory filingdocuments. A petition for approval of EOP-004-2 was filedwith FERC on December 31, 2012.

Project 2010-05.1 Phase 1 of Protection Systems:MisoperationsDescription:A key element for Bulk Electric System(BES) reliability is the correct performance ofProtection Systems. Monitoring BES ProtectionSystem events, as well as identifying and correctingthe root causes of Misoperations, will improveProtection System performance.

Leadership:Mark Kuras, PJMNERC Staff:Al McMeekinSAR Date:6/9/11Team Assembly:6/22/11Target Finish:9/4/12Forecast Finish:11/21/13SPM Step:Responding to CommentsRelated Standards:PRC-004-WECC - Protection Systemand Remedial Action Scheme Misoperation (WECC), PRC-003 - Regional Procedure for Analysis of Misoperationsof Transmission and Generation Protection Systems,PRC-004 - Analysis and Mitigation of Transmission andGeneration Protection System MisoperationsLast Update:1/9/13

Status:The drafting team met November 27-30, 2012 at NERCHQ in Atlanta. The team consulted with the NERC RAPA groupand NERC Legal staff and decided to remove the reportingobligation from the standard. Misoperation reporting will behandled with a RoP Section 1600 data request. The team heldtwo Ready Talk meetings on December 11 & 13, 2012 tocontinue developing responses to comments. The standardsdeveloper will prepare all the associated documents once thedraft standard is completed. The draft standard will be postedfor a successive ballot in January 2013.

Project 2010-14.1 Balancing Authority Reliability-based Controls - ReservesDescription:Revise BAL-001-0.1a, BAL-002-1 anddevelop BAL-012-1 & BAL-013-1

Leadership:Glenn Stephens - Santee Cooper (Chair)Tom Siegrist - EnerVision (Vice-chair)NERC Staff:Darrel RichardsonSAR Date:5/3/07Team Assembly:12/11/07Target Finish:4/10/13Forecast Finish:12/3/13SPM Step:Responding to CommentsRelated Standards:BAL-002 - Disturbance ControlPerformance, BAL-013 - Large Loss of LoadPerformance, BAL-012 - Operating Reserve Planning,BAL-001 - Real Power Balancing Control PerformanceLast Update:1/4/13

Status:The four draft Standards were posted on June 4, 2012for a 30 day formal comment period. The SDT has respondedto comments received from the posting.The project was delayed due to other higher priority projectpostings, but is now being expedited to coordinate withProject 2007-12 Frequency Response.BAL-012-1 was posted for a 45-day comment period and initialballot on November 30, 2012.BAL-001-1, BAL-002-2 and BAL-013-1 are anticipated to beposted for a 45-day comment period and initial ballot duringthe week of January 7, 2013.

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Program: Interpretations(9)

Priority: Normal(6)

Project 2010-INT-03 TOP-002-2a for FMPPNERC Staff:Plan Finish:3/23/11Est. Finish:3/23/11SPM Step:NewRelated Standards:TOP-002-2a, R2, R8 and R19Last Update:5/30/12

Possible candidate for Rapid Revision.

Project 2009-19 Interpretation of BAL-002-0 R4 and R5 by NWPPReserve Sharing GroupNERC Staff:Darrel RichardsonPlan Finish:2/25/13Est. Finish:1/28/13SPM Step:FilingRelated Standards:Last Update:1/4/13

Project restarted based on BOT Action re: the scope of this interpretation and the teams ability to relyon language other than solely the requirements. New chair Al DiCaprio assigned.

The interpretation was posted for comment and ballot. The ballot ended on September 4, 2012. Theinterpretation passed with an 87.78% approval rating. The SDT addressed comments received and arecirculation ballot has been posted (September 28 - October 8, 2012). The re-circulation ballotpassed with an approval rating of 85.11%.

The NERC BOT adopted the draft interpretation during their November 2012 meeting.

Project 2012-INT-06 CIP-003 for ConsumersNERC Staff:Ryan StewartPlan Finish:8/15/14Est. Finish:8/20/14SPM Step:Responding to CommentsRelated Standards:Last Update:1/4/13

Consumers Energy requested interpretation of CIP-003-3 regarding the Applicability Section 4.1 andmultiple functions, and on Requirement R2 regarding whether a Registered Entity can assign differentCIP Senior Managers for different applicable functions for which it is registered. The drafting teamposted Draft 1 of the response to the interpretation request for CIP-003 for a 30-day formal commentperiod, ending December 10, 2012. The drafting team is now responding to comments.

Project 2012-INT-07 CIP-005 for AEPNERC Staff:Ryan StewartPlan Finish:10/17/14Est. Finish:12/24/14SPM Step:DraftingRelated Standards:Last Update:12/18/12

AEP requested clarification on CIP-005 whether for the purposes of access point identification,“externally connected communications endpoints” include those communications links that do notuse either (1) a routable protocol (such as IP), or (2) a dial-up modem. The Interpretation DraftingTeam is drafting the interpretation for AEP and anticipate posting for an initial comment period in Q1of 2013.

Project 2012-INT-05 CIP-002-3 for OGENERC Staff:Steven NoessPlan Finish:2/14/14Est. Finish:2/26/14SPM Step:Recirculation BallotRelated Standards:Last Update:1/8/13

Asks for clarification about applicability of CIP-002-3 R1.2.5 to Advanced Meter Infrastructure (AMI)systems (i.e., whether AMI systems must be considered in an entity's risk-based assessmentmethodology under CIP-002). The interpretation completed a 45 day formal comment period andparallel initial ballot on December 20, 2012. The initial ballot achieved industry approval of 95.60%.The IDT anticipates posting for recirculation ballot in January 2013 and submitting to the NERC BOT, ifapproved, for consideration during the February 2013 BOT meeting.

TBD RFI received on 7/22/11 from EEI and NRECA on CIP-001-1NERC Staff:Plan Finish:11/1/11Est. Finish:11/1/11SPM Step:NewRelated Standards:CIP-001Last Update:10/1/12

In August the SC voted to move forward with this interpretation. Drafting team appointment on holdpending finalization of CAN-0016 to see if the revision of the CAN provides clarification. In September,the SC reaffirmed this decision. On January 25, 2012, EEI and other trade organizations submitted anappeal of CAN-0016. The results of the appeal were posted to the NERC website on February 8, 2012.

Priority: High(3)

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Project 2012-INT-04 CIP-007 for ITCNERC Staff:Steven NoessPlan Finish:6/11/14Est. Finish:7/16/14SPM Step:Initial BallotRelated Standards:CIP-007Last Update:1/8/13

Interpretation requests clarification on CIP-007-3, Requirement R5.3. Specifically, the questions relateto the use of “technical and procedural controls” in Requirement R5, and whether each sub-requirement requires both technical and procedural controls. The interpretation completed its firstformal comment period on December 10, 2012, and the IDT is responding to comments and preparingthe interpretation for initial ballot. This request for interpretation is similar to the request forinterpretation in Project 2012-INT-03 (TECO), which is on hold pending the outcome of thisinterpretation.

Project 2009-22 Interpretation of COM-002-2 for the IRCNERC Staff:Joseph KrisiakPlan Finish:4/5/12Est. Finish:1/24/13SPM Step:FilingRelated Standards:COM-002-2, R2Last Update:1/8/13

The filing for the project 2009-22, COM-002-2a, R2 Interpretation will coincide with the filing of andproject 2006-06, COM-002-3 and project 2007-02, COM-003-1. The target for filing will depend on theFebruary 2013 BOT meeting results.

NERC staff is preparing the filing documents for the February 2013 BOT review and action and forFERC approval in 2013. Update current as of 1-07-13

Project 2012-INT-02 TPL-003-0a & TPL-004-0 for SPCSNERC Staff:Scott Barfield-McGinnisPlan Finish:8/7/13Est. Finish:8/2/13SPM Step:Responding to CommentsRelated Standards:TPL-003-0a, TPL-004-0Last Update:1/7/13

The interpretation 45-day formal comment period and initial ballot (72.57%) ended December 5. Theteam is considering comments and working toward its next posting and recirculation ballot in earlyJanuary 2013 and a February BOT adoption. This meets one of the three approaches identified in theOrder No. 754 technical conference.

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Projects under Active Development Projected Posting Schedule

Information

This provides supplemental information to the Project Master Scheduler graph previously posted for the December Standards Committee meeting. A chart reflecting the below projected postings through February 2013 is included. This information is subject to change. Projected Postings

• Project 2013-02 P81 (possible recirculation ballot)

To be posted during the week of January 7:

• Project 2010-14.1 BARC: BAL-001-1, BAL-002-2, BAL-013-1 (45-day comment period and initial ballot)

To be posted during the week of January 14:

• Project 2010-13.2 Generator Relay Loadability, PRC (45-day comment period and initial ballot) • Project 2012-INT-02 Interpretation of TPL-003-0a and TPL-004-0 for SPCS Recommendations (possible recirculation ballot) • Project 2012-INT-05 Interpretation of CIP-002-3 for OGE (possible recirculation ballot) • SPM Revisions to Implement SPIG Recommendations (possible recirculation ballot)

• Project 2007-09 Generator Verification – PRC-024-1 (possible recirculation ballot)

To be posted during the week of January 21:

• Project 2010-11 TPL FN “b” (possible recirculation ballot)

• Project 2010-05.1 Protection Systems: Phase 1 (Misoperations) – PRC-004-3 (30-day comment period and successive ballot)

To be posted during the week of January 28:

• Project 2010-14.1 BARC: BAL-012-1 (30-day comment period and successive ballot)

To be posted during February 4:

To be posted during February 11:

• Project 2012-INT-04 Interpretation of CIP-007 for ITC (45-day comment period and initial ballot) • Project 2012-INT-06 Interpretation of CIP-003-3 (45-day comment period and initial ballot)

• N/A

To be posted during February 18:

• Project 2007-06 System Protection Coordination – PRC-027-1 and PRC-001-3 (30-day comment period and successive ballot)

To be posted during February 25:

• Project 2007-02 Operating Personnel Communication Protocols – COM-003-1 (30-day comment period and successive ballot)

Project 1/7 1/14 1/21 1/28 2/4 2/11 2/18 2/25

Project 2010-11 TPL FN ‘b’

Project 2013-02 P. 81

Project 2007-02 – COM-003

SPM Revisions

Project 2007-12 Frequency Resp.

Project 2010-17 DBES Guidance Doc

Project 2010-17 DBES Phase 2

Project 2007-09 Generator Verification

Project 2007-09 Generator Verification

Project 2007-09 Generator Verification

Project 2007-09 Generator Verification

Project 2007-09 Generator Verification

Project 2007-06 PRC-027

Project 2010-05.1 PRC-004

Project 2010-14 BARC

Project 2010-14 BARC

Project 2010-14 BARC

Project 2010-14 BARC

Project 2010-13.2 Gen Relay Load. PRC

Project 2012-INT-02

Project 2012-INT-04 CIP-007 Interpretation

Project 2012-INT-05 CIP-002-3 Interpretation

Project 2012-INT-06 CIP-003 Interpretation

Number of Standards Posted 3 8 9 7 6 8 8 5

If Standards Committee members have questions or need additional information, they may contact Mark Lauby at [email protected] or Kristin Iwanechko at [email protected].

Projected for Feb BOT Projected for May BOT Draft SAR 30-day comment period 45-day comment period and initial ballot 30-day comment period and successive ballot Possible recirculation ballot depending on previous ballot results

NERC | Standards Committee Strategic Plan | January 8, 2013 1 of 5

St a n d a rd s Com m it t e e St ra t e g ic Pla n January 8, 2013

3353 Peachtree Road NE Suite 600, North Tower

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

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NERC | Standards Committee Strategic Plan |January 8, 2013 2 of 5

Table of Contents Table of Contents ......................................................................................................................................................................... 2 Introduction ................................................................................................................................................................................. 3

Current State of Reliability Standards ...................................................................................................................................... 3

Vision, Mission, and Guiding Principles ....................................................................................................................................... 4 Vision ....................................................................................................................................................................................... 4

Mission ..................................................................................................................................................................................... 4

Guiding Principles .................................................................................................................................................................... 4

Areas of Strategic Focus ............................................................................................................................................................... 5

NERC | Standards Committee Strategic Plan |January 8, 2013 3 of 5

Introduction The Electric Reliability Organization (ERO or NERC) is responsible under a unique regulatory model in which industry technical expertise and subject matter experts are engaged in the development of Reliability Standards. The NERC Board of Trustees (Board or BOT) is responsible for establishing strategic priorities for NERC, including ensuring that the development and maintenance of Reliability Standards is carried out in a timely and efficient manner to meet regulatory obligations. NERC, the Regional Entities and industry stakeholders have made significant mutual investments to maintain the unique ERO regulatory model. The Standards Committee (SC) is a stakeholder-based committee designed to manage and oversee the development of Reliability Standards, while ensuring the success of the ERO model and the integrity of the process. This Strategic Plan sets forth the vision and mission for the SC. Based on this Plan, a companion Standards Committee 2013-2015 Strategic Work Plan (Work Plan) outlines the changes in the SC charter and SC processes. These changes include enhancements and course improvements that are intended to achieve the following: (i) increasing the SC’s accountability for the effective execution of the Standards development process, including Reliability Standards that are timely developed, technically excellent and developed through an industry consensus building process; (ii) reforming the Standards development process, as needed, to achieve an end-state that is defined by a set of high quality Reliability Standards that support the reliability of the bulk power system; and (iii) achieving an end-state that provides clear compliance expectations and predictable, consistent compliance assessment. The processes involved in development of these end state objectives shall continue to use the technical expertise of the industry, combined with establishing and/or restructuring the SC subcommittees, working groups and standards drafting teams as necessary and appropriate to meet the goals of this Strategic Plan. Although this Strategic Plan sets forth a mission, vision and briefly outlines a Work Plan, it is meant to be a “living document” that will be reviewed and revised as needed in the fourth quarter each year. Also, in the event additional key strategic changes emerge, the SC will revisit this Strategic Plan to ensure alignment with the ERO strategic goals.

Current State of Reliability Standards The current set of NERC Reliability Standards includes the following: (i) version zero Reliability Standards; (ii) Reliability Standards that have been revised to address Federal Energy Regulatory Commission (FERC) directives; (iii) Reliability Standards that still need to be revised, or more completely revised, to address outstanding FERC directives; (iv) Reliability Standards that are due or overdue to undergo a periodic year review and (v) Reliability Standards that have accompanying requests for interpretation or Compliance Application Notices (CANs) attempting to clarify requirements. At present, there are 121 mandatory Reliability Standards with more under development. Many of these standards share common reliability objectives and principles, and address similar tasks and conditions, and, as such, may be redundant to each other. Hence, there may be an opportunity to gain efficiencies through combining, refining or consolidating some of the Reliability Standards. Further, many Reliability Standards have yet to be converted to a results-based approach; and some standards may, as FERC stated, contain requirements that “provide little protection for Bulk-Power System reliability or may be redundant.”1

Transitioning from this mix of Reliability Standards to a comprehensive set of high quality, technically sound, clear, results-based Reliability Standards requires the implementation of the enhancements, changes in accountability and course improvements set forth in this Strategic Plan.

At the October 2012 meeting, the SC initiated the development of this Strategic Plan and the associated Work Plan to guide the SC and its subcommittees in the development of their work plans. Thereafter, at its November 7, 2012 meeting, the NERC Board passed four resolutions that further guided the development of this Strategic Plan.2

To execute on the initiatives of the October 12, 2012 meeting and the BOT resolutions, the SC at its December 2012 meeting adopted this Strategic Plan to provide a clear focus for the SC and its subcommittees’ activities and efforts. Also, at its January 2013 meeting, the SC adopted the accompanying Standards Committee 2013-2015 Work Plan that more specifically sets forth the enhancement and course improvements of the SC activities.

1 North American Electric Reliability Corporation, 138 FERC ¶ 61,193 at p 81 (March 15, 2012). 2 NERC November 7, 2012 Board of Trustees Meeting - Agenda Item 7e.1

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Vision, Mission, and Guiding Principles Vision A comprehensive set of results-based Reliability Standards that collectively help ensure the reliable operation of the North American bulk power system. Mission The SC’s mission is to effectively manage and oversee the development of a comprehensive set of Reliability Standards that are aligned with the ERO’s strategic goals through open and inclusive processes and procedures.

Guiding Principles • Ensure the development of high quality results-based3

• Effectively execute the Standards development process with an efficient use of NERC and industry resources through effective project management and oversight to achieve the timely completion of Standard development projects.

Reliability Standards through a comprehensive multi-year standard development plan that is aligned with the ERO’s strategic goals.

• Transition to a comprehensive set of Reliability Standards that are high quality, technically sound, clear and results-based.

• Use collaboration, technical resources and outreach to key stakeholder groups and NERC and regional technical committees to facilitate consensus-building prior to and throughout all stages of the Standards development process.

• Ensure that alternative approaches to meet the reliability objective of proposed standards are considered to achieve cost effective solutions, preferably in the informal collaborative process.

3 Consistent with the SPM, results-based shall have the following meaning:

• Performance-based Requirements define a specific reliability objective or outcome that has a direct, observable effect on the reliability of the Bulk Power System, i.e. an effect that can be measured using power system data or trends.

• Risk-based Requirements define actions of entities that reduce a stated risk to the reliability of the Bulk

Power System and can be measured by evaluating a particular product or outcome resulting from the required actions.

• Capability-based Requirements define capabilities needed to perform reliability functions and can be

measured by demonstrating that the capability exists as required.

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Areas of Strategic Focus The SC recognizes the need and benefit of focusing on the following strategic areas while also maintaining an ongoing strategic focus on an alignment with the NERC ERO enterprise strategic goals, including the top priority issues of the ERO. The SC and its subcommittees provide the oversight, guidance and leadership essential to address these areas of strategic focus efficiently and comprehensively, and ensure technical accuracy, with the objective of enhancing bulk power system reliability. Further, the SC recognizes the need to strengthen the ties between the NERC and regional technical and standing committees to ensure expertise is leveraged and amplified in the standards development process thereby increasing the relevance and value of the technical and standing committees to increasing bulk power system reliability. The following areas of strategic focus are identified to produce significant progress in 2013 and 2014 toward a comprehensive set of Reliability Standards that are high quality, technically sound, clear, results-based, and, that also address outstanding regulatory directives while retiring any requirements that provide little protection for bulk power system reliability or may be redundant.

1. Transition the current body of standards – Complete the transition to a stable, world-class set of clear, concise results-based standards that ensure the reliability of the bulk power system.

2. FERC Directives and Recommendations from the 2003 Blackout Report – Target a filing to resolve all currently outstanding FERC directives by the end of 2013.

3. Periodic Review of Reliability Standards – Complete any periodic reviews of Reliability Standards as called for in the NERC Standard Processes Manual and develop an approach to ensure periodic reviews are completed in a timely fashion.

4. Finish remaining open Standard projects – Focus project management on open Standard development projects for completion by the end of 2013. Closure in some instances may involve a recommendation to stop some projects, consolidate projects or roll them into the Directives project. Projects that cannot be completed by end of 2013 will have a specified completion date agreed to by the SC.

5. Paragraph 81 and Results-Based Standards concepts – Apply Paragraph 814 (retire or modify FERC-approved Reliability Standard requirements that as FERC noted, "provide little protection to the reliable operations of the BES", are redundant or unnecessary) and Results-Based Standards5

6. Existing or Emerging Issues and Reliability Risks – In consultation with RISC, address emerging risks to the bulk power system by developing high quality and technically sound Reliability Standards, as needed, and in a timely manner.

concepts across the above mentioned major work areas (2-4) during their completion.

7. Maintenance of Existing Reliability Standards – In conjunction with the periodic review process, continue to review existing Reliability Standards to ensure the standards remain up-to-date. Provide interpretations on Reliability Standards as required in the Standards Process Manual.

8. Compliance and Enforcement Input – Coordinate Reliability Standards with NERC’s compliance and enforcement programs and associated tools.

4 Information regarding Paragraph 81 can be located on the project page for Paragraph 81 Phase I on the NERC website. 5 Information regarding Results Based Standards can be located on the NERC website under Resource Documents for Standards.

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Table of Contents Table of Contents ......................................................................................................................................................................... 2 Introduction ................................................................................................................................................................................. 3 Implementation Plan ................................................................................................................................................................... 4

Work Plan ................................................................................................................................................................................ 4

Accountability to BOT .......................................................................................................................................................... 4

Smaller, more agile and committed SDTs ............................................................................................................................ 4

Aggressively oversee and manage the workflow and effective use of the Standards development process ..................... 4

Implementation Tasks ................................................................................................................................................................. 6 Task No. 1: SC Accountability – Review of the Standards Committee Charter: ....................................................................... 6

Implementation ................................................................................................................................................................... 6

Task No. 2: Review of the Standards Processes and Procedures: ........................................................................................... 6

Implementation: Review the Standards Development Process ......................................................................................... 6

Task No. 3: Three Reliability Standard Development Plan Work Areas ................................................................................... 7

Implementation: .................................................................................................................................................................. 7

Task No. 4: Interaction with RISC ............................................................................................................................................. 7

Implementation: .................................................................................................................................................................. 7

Task No. 5: Training and Outreach........................................................................................................................................... 7

Implementation: .................................................................................................................................................................. 7

Task No. 6: Review of SC and its subcommittees and affiliated working groups ................................................................... 8

Implementation: .................................................................................................................................................................. 8

Task No. 7: Increased Access to Subject Matter Experts ........................................................................................................ 8

Implementation: .................................................................................................................................................................. 8

Task No. 8: Increase collaboration .......................................................................................................................................... 8

Implementation: .................................................................................................................................................................. 8

Task No. 9: Project Management and Oversight Subcommittee ............................................................................................ 8

Implementation: .................................................................................................................................................................. 9

Task No. 10: Outstanding Projects (2014-2015) ..................................................................................................................... 9

Task No. 11: Coordination with Compliance ............................................................................................................................ 9

Implementation: .................................................................................................................................................................. 9

Task No. 12: SC Communications and Planning Subcommittee to communicate with Stakeholders about Standards Committee activities to facilitate consensus building and stakeholder buy-in. ...................................................................... 9

Implementation: ................................................................................................................................................................ 10

Task No. 13: Annual review of Strategic Plan and Work plan ............................................................................................... 10

Implementation: ................................................................................................................................................................ 10

Appendix A: 2013 Tasks ............................................................................................................................................................. 11 Appendix B: Standards Committee Organizational Chart .......................................................................................................... 14

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Introduction At the October 2012 meeting, the Standards Committee (SC) initiated the development of a strategic plan to guide the SC and its subcommittees in the development of their work plans. Thereafter, at its November 7, 2012 meeting, the NERC Board of Trustees (BOT or Board) passed resolutions related SC activities, which further guided the development of the Strategic Plan and this companion Strategic Work Plan (Work Plan). The 2013-2015 Work Plan is the tactical implementation plan for the SC Strategic Plan. As a tactical plan, this it is a living document that is meant to address the current strategic issues. To ensure the Work Plan is current and consistent with the Strategic Plan, an annual fourth quarter review shall be completed as part of the overall development of the Reliability Standards Development Plan (RSDP) and to update this Work Plan, as needed.

Implementation Plan

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Implementation Plan Work Plan The following are the key tactical recommendations to implement the SC strategic plan. The details related to this Implementation Plan are set forth in the following Implementation Tasks section, Appendix A (which includes milestones and due dates) and the revised SC organizational chart in Appendix B: Accountability to BOT Review and revise, as necessary, the SC charter, processes and procedures to emphasize SC accountability to the BOT for the timely completion of Standard development projects that produce high quality, technically sound, clear, results-based Reliability Standards. These changes shall include enhancing the SC’s review of draft and final SARs and the work product of Standard Drafting Teams (SDTs) as consistent with producing high quality, technically sound, clear, results-based Reliability Standards.1

Smaller, More Agile and Committed SDTs Ensure the SC appoints, monitors and directs agile and focused SDTs that generally consist of no more than ten appointed stakeholder members, who are suitably equipped with the skill sets to address the objectives of the standard being drafted (e.g., subject matter experts (SMEs), a chairperson,2 technical writer and compliance, legal and regulatory experts).3

Stakeholders can perform one or more of these roles. NERC will assign a project manager (i.e., standards developer) to each SDT. The standards developer will coordinate closely with the SDT meeting facilitator. In each case, the chairperson and project manager shall work closely with the SC Project Management and Oversight Subcommittee (PMOS), as set forth below.

Each SDT member must commit to have the willingness and ability to devote the time and effort necessary to meet the project schedule. Also, to promote the effectiveness of the smaller SDTs, NERC staff and stakeholder facilitators, technical writers and legal/regulatory experts shall assist SMEs to draft documents during and in between meetings. Further, NERC staff, with the active support of the SC, shall create pools of SMEs (e.g., BAL SMEs, TPL SMEs, CIP SMEs and the like) who will act as technical consultants for the smaller, more agile SDTs as well as the SC.4

These pools of SMEs shall not be formal members of a SDT, but may be called on from time-to-time by a SDT or SC to assisting in the understanding of technical issues.

Aggressively Oversee and Manage the Workflow and Effective Use of the Standards Development Process The SC shall develop a comprehensive set of high-quality, technically sound, clear, results-based Reliability Standards in a timely manner. To achieve this goal, the SC shall:

• Implement the following major work areas through the Reliability Standards Development Plan:

1 The Standards Processes Manual (SPM) at page 12 provides that the SC may accept, remand, reject or delay action draft SARs. After posting, the SPM at page 14 authorizes the SC, based on public comments, authorize the drafting of Reliability Standard requirements or reject the SAR. The SPM at pages 8-9 states that: “The Standards Committee has the right to remand work to a drafting team, to reject the work of a drafting team, or to accept the work of a drafting team. The Standards Committee may direct a drafting team to revise its work to follow the processes in this manual or to meet the criteria for NERC’s benchmarks for Reliability Standards, or to meet the criteria for governmental approval; however, the Standards Committee shall not direct a drafting team to change the technical content of a draft Reliability Standard.” 2 It is expected that the chairperson will serve as the meeting facilitator. 3 The SPM at page 14 states that: “The Standards Committee may also supplement the membership of a Reliability Standard drafting team at any time to ensure the necessary competencies and diversity of views are maintained throughout the Reliability Standard development effort.” 4 The technical consultants may be requested by the SC to provide their opinion during the review of SARs or SDT work product.

Implementation Plan

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o Address outstanding regulatory reliability directives and recommendations from the 2003 Blackout Report;

o Address NERC’s periodic standard review obligation; and

o Prioritize and complete on-going Standards development projects and any emerging issues.

Paragraph 815 and Results-Based Standards6

• Integrate the interaction/processes with the Reliability Issues Steering Committee (RISC) foundational work efforts, including ranking, prioritization, and completion of the standards work.

concepts will be applied across these three major work areas during their completion:

• Engage the Operating Committee (OC), Critical Infrastructure Protection Committee (CIPC) Planning Committee (PC), RISC, and regional committees to develop a process to obtain technical inputs to aid Standards development when needed.

• Establish enhanced consensus building, collaborative and communication approaches for the SC and stakeholders to use prior to the approval of a new Standards development project and throughout the Standards development process. Similarly, establish enhanced communication plans for SDTs to provide for greater consensus building and collaboration.

• Establish a new SC (PMOS) to ensure the timely completion of high quality, technically sounds, clear and results-based Reliability Standards. The SC PMOS will work with NERC staff to develop project timelines prior to the commencement of a project, so that prospective members of a SDT can understand and commit to meeting the project timeline, including milestones, at the time of their nomination or appointment and enable the PMOS to ensure that each SDT is on schedule and meets its milestones and deadlines. The SC shall also ensure that the smaller SDTs call on, as needed, one or more experts from the applicable pool of SMEs. For example, if a MOD SDT needs to understand how a MOD issue is handled in Electric Reliability Council of Texas (ERCOT), it shall call on the MOD SME with ERCOT expertise to answer any questions and provide guidance.

o The new SC PMOS may also request that a SC member act as a liaison with a specific SDT to provide guidance and oversight, and to communicate back to the subcommittee on any concerns or issues.

• Address, as necessary, the need to revise training, processes and procedures, such as the Ten Benchmarks of Excellent Reliability Standards, to emphasis results-based requirements.

• The SC to collaborate with NERC compliance and enforcement staff to provide policy inputs to the Compliance Monitoring Enforcement Program and compliance elements.

• Review the charters of the SC and its subgroups to ensure these documents are properly organized to accomplish the mission described in the SC strategic plan.

5 Information regarding Paragraph 81 can be located on the project page for Paragraph 81 Phase I on the NERC website. 6 Information regarding Results Based Standards can be located on the NERC website under Resource Documents for Standards.

Implementation Tasks

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Implementation Tasks The following is a work plan with specific implementation tasks. Tracking of the responsibility for completing the implementation tasks and associated deadlines are set forth in Appendix A.

Task No. 1: SC Accountability – Review of the Standards Committee Charter: Implement revisions needed to the SC charter to enhance the SC’s accountability to the BOT, including the delivery of high quality and timely Reliability Standards and the execution of the Strategic Plan. All revisions, creation or elimination of SC charter provisions or proposed changes to the Rules of Procedure/SPM shall be presented to the full SC for review and adoption, prior to presenting to the BOT for approval. Options to be considered by the SC: Implementation The SC shall develop a comprehensive set of high-quality, technically sound, clear, results-based Reliability Standards in a timely manner. To achieve this goal, the SC shall:

The SC ad hoc strategic vision sub-team shall review the SC Charter and other governing documents, including the NERC Rules of Procedure/SPM, based on the Strategic Plan, BOT resolutions and to prepare proposed SC Charter and NERC Rules of Procedure/SPM revisions for SC review and adoption.7

a. That the SC is accountable to the BOT to effectively manage and oversee the timely development of a comprehensive set of high quality, technically sound, clear, results-based Reliability Standards that address regulatory directives and meeting reliability needs.

The criteria for this review will include SC accountability for effective management of the Standards development process, timely completion of Standard projects and consensus building. Flexibility should also be considered in the review to ensure that appropriate safeguards are established for an open, transparent and consensus-building process, while ensuring that processes are geared towards the timely development of Reliability Standards. The review and proposed changes, therefore, shall, at a minimum, include the following:

b. That the SC oversees that the SDTs produce timely, high quality, technically sound, clear, results-based Reliability Standards.

c. That the BOT approve the elections of the SC chair and vice chair. d. Term limits on the chair and vice chair positions. e. That the SC and SDT members shall maintain the highest ethical standards in their membership obligations. f. That the SC shall only approve SDT members that are committed to the project schedule and meeting the

reliability objective of the project. g. That the SC (with assistance of the chair and vice chair) employs consensus building, collaborative and

communication processes prior to the approval of a new Standards development project and throughout the Standards development process.

Task No. 2: Review of the Standards Processes and Procedures: Implement revisions needed to NERC’s Rules of Procedure/SMP and SC processes and procedures to enhance SC and SDT accountability to timely delivery high quality Reliability Standards and execute the Strategic Plan, including the completion of Standards Process Input Group (SPIG) recommendations. All revisions, creation or elimination of processes and procedures provisions shall be presented to the full SC for adoption, prior to presenting to the BOT for approval. Implementation: Review the Standards Development Process The SC Process Subcommittee (SCPS) shall review all aspects of the Standards development process map. The criteria for this review will include increasing effectiveness, timely completion and consensus building. Flexibility should be considered in the review to ensure that appropriate safeguards for open, transparent and consensus construction are part of process,

7 Rules of Procedure/SPM changes shall be posted for stakeholder comment and balloting consistent as required by the NERC Rules of Procedure.

Implementation Tasks

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while ensuring that it is geared towards production, and cannot be used for obstruction. The SCPS shall identify each step and the need to enhance or revise each step to conform to the SPIG recommendations and BOT resolutions. After process mapping is complete, SCPS shall draft proposed revisions to processes, procedures and NERC Rules of Procedure/SPM, as necessary, which shall include, at a minimum, the following:

For processes and procedures:

Include coordination with the NERC standing committees. Coordination should include the following: (i) receiving technical research or input from the committees prior to a standard being developed, as necessary, and (ii) a technical review of the draft standards.

For the NERC Rules of Procedure/SPM:

a. That the SC has the authority to approve draft and final SARs and the work product of SDTs as consistent with producing high quality, technically sound, clear and results-based Reliability Standards.

b. Review the need for, or reshaping of, the quality review process in light of the new composition of the SDTs.

c. Periodically review the requirement to follow the ANSI process with a weighing of ANSI’s effectiveness and efficiency. Determine whether employing ANSI principles are sufficient.

Task No. 3: Three Reliability Standard Development Plan Work Areas The SC and NERC Staff shall work together to develop a work plan for the coordination and deployment of the Standard work areas, applying Results-Based Standards concepts:

• Address outstanding regulatory reliability directives and recommendations from the 2003 Blackout Report; • Address NERC’s periodic standard review obligation; • Address the completion of on-going and pending Standards development projects and any new projects required

to address merging issues; and • Continue to apply the Paragraph 81 concepts (i.e., retire or modify FERC-approved Reliability Standard

requirements that provide little protection to the reliable operations of the BES, are redundant or unnecessary, or retire or modify a FERC-approved Reliability Standard requirement to increase the efficiency of the ERO’s compliance programs) in all active projects.

Implementation: The revised RSDP shall be presented to the SC for adoption. The SC and NERC staff shall implement a collaborative process with interested stakeholders, as appropriate, to develop any SARs resulting from the work plan.

Task No. 4: Interaction with RISC Integrate the interaction and processes with the RISC foundational work efforts, including ranking, prioritization and completion of the standards work. Coordination should include the following: (i) receiving technical research or input from NERC standing and technical committees prior to a standard being developed, as necessary, and (ii) a technical review of the draft standards. Implementation: The SC will work with RISC to develop a work plan.

Task No. 5: Training and Outreach Outreach to stakeholders and provide training to SDTs on the revised SC charter processes and procedures related to the Standards project development. Implementation: The SC Communications and Planning Subcommittee (SCCPS) and NERC staff shall work together to facilitate the development of communication and deploy training via webinars, etc. on the three Standard work areas and revised SC charter, processes and procedures. The SCCPS shall also facilitate the development of training for SDT members on the

Implementation Tasks

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new configuration of SDTs, which will include a skilled facilitator, uses legal and regulatory experts, project managers, technical writers, compliance experts and the pool of SMEs working together to develop high quality, technically sound, clear, and results-based Reliability Standards. The SCCPS shall facilitate the development of kick-off training for SDT members in the following areas:

• Results-Based Standards development • Project Management skills and responsibilities • Quality Review principles • Resources to resolve issues

Task No. 6: Review of SC and its Subcommittees and Affiliated Working Groups The SC will evaluate the following to align their objectives with the strategic plan: (1) the membership of the SC, starting with the 2014 elections; (2) the duties of the Executive Committee of the SC and (3) the SCPS, and (4) the Functional Model Working Group (FMWG). These reviews are to be completed and implemented by June 2013. Implementation: The SC Executive Committee shall develop recommendations for the full SC on: (1) whether to revise the membership composition of the SC; and (2) the responsibilities and authority of the SC Executive Committee and its role in relation to the full SC (for example: agenda setting, posting of project documents). The SCPS shall develop recommendations for the full SC to align the scope the SCPS to focus its work on productive and quality control, rather than the production of procedures. The FMWG shall develop recommendations for the full SC on whether to continue the operation of the FMWG. These recommendations should be presented for SC consideration at the SC’s March face-to-face meeting.

Task No. 7: Increased Access to Subject Matter Experts An increased pool of industry experts are needed who can quickly address pressing Reliability Standards issues. Therefore, the NERC staff, with active support of the SC, shall annually solicit pools of SMEs to serve as technical advisors for each of the Standard categories. Implementation: NERC staff shall solicit stakeholders to serve as SME technical advisors for each Standards category. One SME can serve in more than one category. This solicitation should strive to have SMEs for each category from each region of the ERO and represent large and small entities, and include Canadian representation, if possible. The SC will work with the NERC standing committees and stakeholders to develop these pools.

Task No. 8: Increase collaboration Increase collaboration with the NERC standing committees, Trades, NERC Staff and/or Regional Entity Staff on any emerging or new proposed projects/SARs and decisions to dispense of any projects listed in the Reliability Standards Development Plan. Implementation: The SC leadership will increase collaboration with the NERC standing committees, regional committees, Trades, NERC Staff and/or Regional Entity Staff on any emerging or newly proposed projects/SARs. The SC leadership will encourage the involvement of these entities during informal development activities and throughout the development of new standards and modifications. The SC will consider assigning a SC member as a liaison to each standing committee to facilitate collaboration.

Task No. 9: Project Management and Oversight Subcommittee Establish a new SC PMOS that reports to the full SC and works closely with NERC staff (including NERC staff’s project managers) and the SDTs. (See Appendix B for organizational chart). This new subcommittee shall have, at a minimum, the following duties:

Implementation Tasks

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a. Work closely with NERC staff standard developers and the SDTs to establish milestones and deadlines for all SC work activities including responding to SARs and standard projects, ensuring SDTs are adhering to standard drafting principles; • Work with NERC staff to develop project timelines prior to the solicitation of a SDT, so that prospective

members of an SDT can understand and commit to meeting the project timeline, including milestones, at the time of their nomination and appointment.

b. Work with NERC staff and other NERC committees need to evaluate the completeness of the technical basis for proposed SARs and standard projects and make a recommendation to the SC; • Engage NERC and stakeholder technical experts on the various NERC technical, standing and regional

committees. c. Actively monitor and manage the oversight of SDT milestones and deadlines, and extend or expedite milestones

and deadlines, as appropriate; d. Support all SAR drafting teams and SDTs providing a specialized facilitator as may be needed to resolve issues and

increase productivity and quality as needed to reach consensus and/or meet its milestones and deadlines; • As part of the project plans and work activities, SDTs should review their technical work with stakeholder

technical experts and NERC technical, standing and regional committees for consultation, review, comments and endorsement, as needed.

• Ensure SDTs use informal methods to gain consensus; e. Work with NERC staff to develop and refine project management tools for tracking projects and communicating

the status or projects; f. Work with the NERC staff standard developer to ensure that SDT meetings focus on tasks necessary for production

and not on group editing of documents or other tasks that could be accomplished between meetings; and g. Ensure SDTs use informal methods to reach consensus.

Implementation: The SC ad hoc strategic vision sub team shall review and revise the SC charter or the Subcommittee charter, consistent with the description above, to establish the Project Management and Oversight Subcommittee. The SC ad hoc strategic vision sub team shall present the proposed changes to the SC for review and adoption prior to presenting to the BOT for approval.

Task No. 10: Outstanding Projects (2014-2015) Increase collaboration with the NERC standing committees, Trades, NERC Staff and/or Regional Entity Staff on any emerging or new proposed projects/SARs and decisions to dispense of any projects listed in the Reliability Standards Development Plan.

Task No. 11: Coordination with Compliance Continue to provide support and expertise on the potential impact of issues related to compliance documents (e.g., CANs, CARs, RSAWs) and the movement away from zero tolerance and towards internal controls, etc. Develop the compliance assessment information in parallel with the review and update of each standard. These tasks shall be completed in conjunction with the Compliance and Enforcement departments of NERC and the Regional Entities. Implementation: The SC shall provide support and expertise on the potential impact of issues related to compliance documents (e.g., CANs, CARs, RSAWs) and develop compliance assessment information in parallel with the review and update of each standard. These tasks shall be completed in conjunction with the Compliance and Enforcement departments of NERC and the Regional Entities.

Task No. 12: SC Communications and Planning Subcommittee to communicate with Stakeholders about Standards Committee activities to facilitate consensus building and stakeholder buy-in.

Implementation Tasks

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Implementation: SCCPS will support the SC and Standard Drafting Teams by developing and implementing communications plans. Communicate with stakeholders to identify issues and share information. Advise and assist NERC staff and the SC with the Reliability Standards Development Plan. Provide project managers with communication plan alternatives. Assist in reaching out to industry to develop a broad SME pool.

Task No. 13: Annual review of Strategic Plan and Work plan Implementation: The SC will conduct fourth quarter annual review of Strategic Plan and Work Plan.

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Appendix A: 2013 Tasks

Task No. Responsibility Date Due Comments

1 SC ad hoc strategic vision sub-team

The SC ad hoc strategic vision sub-team shall review the SC Charter and other governing documents, including the NERC Rules of Procedure/SPM, based on the Strategic Plan, BOT resolutions and to prepare proposed SC Charter and NERC Rules of Procedure/SPM revisions for SC review and adoption. The criteria for this review will include SC accountability for effective management of the Standards development process, timely completion of Standard projects and consensus building. Flexibility should also be considered in the review to ensure that appropriate safeguards are established for an open, transparent and consensus-building process, while ensuring that processes are geared towards the timely development of Reliability Standards.

Revision to the SC Charter due in final daft to BOT on January 10, 2013; SC to review and approval final SC Charter changes at January 16, 2013 meeting and send BOT redline of any changes. Revisions to processes and procedures/SPM due to SC by end of February 20, 2013.

Revised SC Charter be considered for adopted at SC’s January 16-17 2013 meetings and BOT’s February 6-7, 2013 meetings. Revisions to processes and procedures/SPM to be considered for adopted at SC’s March meetings.

2 SCPS The SC Process Subcommittee (SCPS) shall review all aspects of the Standards development process map. The criteria for this review will include increasing effectiveness, timely completion and consensus building. Flexibility should be considered in the review to ensure that appropriate safeguards for open, transparent and consensus construction are part of process, while ensuring that it is geared towards production, and cannot be used for obstruction. The SCPS shall identify each step and the need to enhance or revise each step to conform to the SPIG recommendations and BOT resolutions. After process mapping is complete, SCPS shall draft proposed revisions to processes, procedures and NERC Rules of Procedure/SPM

Revisions to processes and procedures/SPM due February 20, 2013.

To be considered for adopted at SC’s March meetings.

Appendix A: 2013 Tasks

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Task No. Responsibility Date Due Comments

3 SC and NERC Staff

The revised RSDP shall be presented to the SC for adoption. The SC and NERC staff shall implement a collaborative process with interested stakeholders, as appropriate, to develop any SARs resulting from the work plan.

December 13, 2012

4 SC Leadership and RISC

The SC will work with RISC to develop a work plan.

In time for presentation at SC 2013 March meetings.

5 SCCPS and NERC Staff

The SC Communications and Planning Subcommittee (SCCPS) and NERC staff shall work together to facilitate the development of communication and deploy training via webinars, etc. on the three Standard work areas and revised SC charter, processes and procedures. The SCCPS shall also facilitate the development of training for SDT members on the new configuration of SDTs, which will include a skilled facilitator, uses legal and regulatory experts, project managers, technical writers, compliance experts and the pool of SMEs working together to develop high quality, technically sound, clear, and results-based Reliability Standards.

Training modules due be completed and ready for deployed on or before February 1, 2013.

6 SC Executive Committee

The SC Executive Committee shall develop recommendations for the full SC on: (1) whether to revise the membership composition of the SC; and (2) the responsibilities and authority of the SC Executive Committee and its role in relation to the full SC (for example: agenda setting, posting of project documents). The SCPS shall develop recommendations for the full SC to align the scope the SCPS to focus its work on productive and quality control, rather than the production of procedures. The FMWG shall develop recommendations for the full SC on whether to continue the operation of the FMWG. These recommendations should be presented

February 20, 2013 To be considered for adopted at SC’s March meetings.

Appendix A: 2013 Tasks

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Task No. Responsibility Date Due Comments

for SC consideration at the SC’s March face-to-face meeting.

7 NERC Staff NERC staff shall solicit stakeholders to serve as SME technical advisors for each Standards category. One SME can serve in more than one category. This solicitation should strive to have SMEs for each category from each region of the ERO and represent large and small entities, and include Canadian representation, if possible. The SC will work with the NERC standing committees and stakeholders to develop these pools.

To be initiated in January 2013 and completed no later than end February 2013.

8 SC Leadership The SC leadership to develop work plan to increase collaboration with the NERC standing committees, regional committees, Trades, NERC Staff and/or Regional Entity Staff on any emerging or newly proposed projects/SARs.

As soon as possible, with a presentation at March SC meeting.

9 SC ad hoc strategic vision sub team

The SC ad hoc strategic vision sub team shall review and revise the SC charter or the Subcommittee charter, consistent with the description above, to establish the Project Management and Oversight Subcommittee. The SC ad hoc strategic vision sub team shall present the proposed changes to the SC for review and adoption prior to presenting to the BOT for approval.

Same as Task #1.

Appendix B: Standards Committee Organizational Chart

NERC | Standards Committee Strategic Work Plan 2013-2015| January 8, 2013 14 of 14

Appendix B: Standards Committee Organizational Chart

Standards Committee

Process Subcommittee*

Project Management and Oversight Subcommittee

Standard Drafting Teams

Communications and Planning

Subcommittee

Functional Model Working Group*

SC ExCom

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Table of Contents

Section 1. Purpose ......................................................................................................... 3

Section 2. Reporting ...................................................................................................... 3

Section 3. Overview and Functions ............................................................................. 3

Section 4. Membership .................................................................................................. 4

1. Segment Representation. ............................................................................................................ 4

2. Membership Requirements. ........................................................................................................ 4

3. Resignation from the Committee. ............................................................................................. 4

4. Committee Member Changing Employment ........................................................................... 4

5. Canadian Representation. ........................................................................................................... 5

6. Membership Terms. ....................................................................................................................... 5

7. Vacancies Caused by Election of Officers. .............................................................................. 5

Section 5. Officers .......................................................................................................... 5

1. Selection. .......................................................................................................................................... 5

2. Terms. ............................................................................................................................................... 5

3. Voting. ............................................................................................................................................... 6

4. Duties of the Chair. ....................................................................................................................... 6

5. Duties of the Vice Chair. .............................................................................................................. 6

6. Duties of the Secretary. ............................................................................................................... 6

Section 6. Voting Members’ Expectations and Responsibilities ............................... 7

Section 7. Executive Committee and Subcommittees ............................................... 7

1. Executive Committee. ................................................................................................................... 7

2. Additional Subcommittees, Task Forces, and ad hoc Working Groups. ......................... 8

Section 8. Meetings ....................................................................................................... 8

1. Open Meetings. ............................................................................................................................... 8

2. General Requirements. ................................................................................................................. 8

3. Notice. ............................................................................................................................................... 8

4. Agenda. ............................................................................................................................................. 8

5. Parliamentary Procedures. .......................................................................................................... 8

6. Quorum. ............................................................................................................................................ 8

7. Voting. ............................................................................................................................................... 8

8. Actions without a Meeting. .......................................................................................................... 9

9. Proxies. ............................................................................................................................................. 9

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Section 1. Purpose

The Standards Committee (the Committee) of the North American Electric Reliability Corporation (NERC) manages and executes the Reliability Standards development process for the timely development and maintenance of a comprehensive set of results-based Reliability Standards that collectively provide for the reliable operation of the North American bulk power system.

Section 2. Reporting

The Committee reports and is accountable to the NERC Board of Trustees. The Committee has the responsibility to keep the industry segments informed regarding Reliability Standards. The NERC Board of Trustees shall approve this Charter and any amendments to this Charter pursuant to Section 1300 of the NERC Rules of Procedure.

Section 3. Overview and Functions

1. The Committee develops and maintains a comprehensive set of results-based Reliability Standards that collectively provide for the reliable operation of the North American bulk power system. Specifically, this Committee shall have the following duties:

(a)

(b) Coordinates with the Reliability Issues Steering Committee to develop a Reliability Standard development plan that prioritizes and aggressively pursues work that will result in a body of high-quality, results-based Reliability Standards.

Develops a long-term (multi-year) strategic vision that describes the goals and direction for development of Reliability Standards consistent with the strategic and business plans of NERC.

(c) Establishes and facilitates the informal and formal collaborative, consensus building processes with stakeholder groups and NERC standing, technical and regional committees throughout all stages of Reliability Standards development.

(d) Establishes quality assurance and quality control process for Reliability Standards that addresses factors including clarity, completeness, sufficient detail, rational result, auditable and enforceable as well as compatible with existing Reliability Standards, and in alignment with (a).

(e) Appoints, monitors and directs agile and focused standard drafting teams that generally consists of no more the ten SC appointed members. The drafting teams should be suitably equipped to address the desired reliability objectives (i.e., subject matter experts, a facilitator, a technical writer and compliance, legal and regulatory experts).

(f) Receives and responds to decisions of appeals panels in accordance with the Reliability Standards process.

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(g) Develops, maintains and implements a Standards Process Manual that ensures the integrity of Reliability Standards development in a manner that is fair, balanced, open and inclusive.

Section 4. Membership

1. Segment Representation.

The Committee membership consists of two members elected from each industry segment. Each industry segment may establish its own rules for electing and replacing its representatives to the Committee consistent with the following requirements:

2. Membership Requirements. 1. No two persons employed by the same corporation or organization or by its affiliates

may serve concurrently as Committee members.

2. Any Committee member who has a membership conflict of this nature is obligated to notify the Committee secretary, who shall inform the Committee chair.

3. Members impacted by such a conflict, such as through a merger of organizations, may confer between themselves to determine which member should resign from the Committee and notify the Committee secretary and chair. If the conflict is not resolved in a timely manner by the impacted members, the Committee chair shall notify all members of the affected industry segments recommending actions to resolve the conflict. If the membership conflict is still unresolved, the Committee chair shall take the conflict to the NERC Board of Trustees for resolution.

4. Any Committee member aware of an unresolved membership issue shall notify the Committee chair.

3. Resignation from the Committee. Any member of the Committee who chooses to resign from the Committee shall submit a written resignation to the Committee secretary and the Committee chair.

1. The Committee secretary shall facilitate the election of a replacement member from the applicable industry segment. The new member shall serve the remainder of the vacant member’s term.

2. If any member of the Committee fails to attend or sends a proxy for more than two consecutive regularly scheduled meetings and/or conference calls, or more than two e-mail ballots between regularly scheduled meetings, the Committee chair shall send a written notice to that member. The member shall be advised to submit a resignation or to request continuation of the membership with an explanation of any extenuating circumstances. If a written response is not received from the member within 30 days of the date of the written notice, the lack of response shall be considered a resignation.

4. Committee Member Changing Employment 1. Any Committee member who resigns from one organization and is subsequently

employed by another organization in the same industry segment shall have the option to retain the membership position.

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2. If a member changes employment to an organization in a different industry segment, then that member shall resign from the Committee no later than the date of the employment change. The resignation letter shall be addressed to the Committee chair, and the chair shall send a letter to the Committee secretary, requesting that an election be held to fill the vacant Committee position.

5. Canadian Representation. If at any time the regular Committee election does not result in at least two voting members being seated from Canada, then up to two Canadian members garnering the highest percentage of votes within their segment will be chosen as additional members of the Committee. The preference is to have the Canadian nominees fill any segment vacancies for which they are qualified.

6. Membership Terms.

Committee members shall serve a term of two years without limitation to the number of terms the members may serve, with members’ terms staggered so that half of the member positions (one per segment) are refilled each year by industry segment election. Membership terms start on January 1 of each year.

7. Vacancies Caused by Election of Officers.

The vacancies in the Industry Segments and/or Canada representation created by the selection of the chair and vice chair shall be filled at the annual election of representatives to the Committee that is next held. When a representative is elected to serve as the chair or vice chair during the second year of a two year term, the representative elected to fill the vacancy shall serve a one year term.

Section 5. Officers

1. Selection. Prior to the annual election of representatives to the Committee in odd numbered years, the members of the Committee shall select a chair and vice chair from among its members by majority vote of the members of the Committee. The newly elected chair and vice chair shall not represent the same Industry Segment. A nominating committee shall solicit nomination for chair and vice-chair no less than 30 days prior to the election. The nominating committee shall consult with the chair of the NERC Board of Trustees’ Standards Oversight and Technology Committee on the nominations received.

Ten days before the election, the nominating committee shall provide to the Committee the qualifications of the nominees proposed. Also, at the time of the election the Committee can accept nominations from the floor. Following the election, the successful candidates shall be presented to the NERC Board for approval. The chair and vice chair, upon assuming such positions, shall cease to act as representatives of the Industry Segments that elected them as representatives to the Committee and shall thereafter be responsible for acting in the best interests of the members as a whole.

2. Terms. The term of office for both the Committee chair and vice chair is one full two year term, which does not include completing the remaining term in the case of early resignation of the previous chair and vice chair.

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3. Voting. The Committee chair and vice chair are non-voting members of the Committee

4. Duties of the Chair. In addition to the duties, rights and privileges discussed elsewhere in this document, the Committee chair has the responsibility to:

1. Preside and provide general supervision of Committee and Executive Committee activities and meetings.

2. Provide general supervision of Committee activities.

3. Manage the progress of all Committee meetings, including the nature and length of discussion, recognition of speakers, motions and voting.

4. Lead informal consensus-building activities prior to and throughout all stages of the Reliability Standards development process.

5. In concert with NERC Staff, schedule all Committee meetings.

6. Review all substitute or proxy representatives.

7. Act as spokesperson for the Committee at forums within and outside NERC.

8. Attend and report Committee activities to the NERC Board of Trustees.

9. Report all views and objections when reporting on items brought to the Committee.

10. Perform other duties as directed by the NERC Board of Trustees.

5. Duties of the Vice Chair. The Committee vice chair shall act as the Committee chair if requested by the chair (for brief periods of time) or if the chair is absent or unable to perform the duties of the chair. If the chair resigns prior to the next scheduled election, the Committee vice chair shall act as the chair until the Committee selects a new chair. The vice chair has the responsibility to:

1. Assist the Committee chair.

2. Attend meetings of the NERC Board of Trustees in the absence of the chair.

3. Assist the Committee chair in managing the progress of all Committee meetings, including the nature and length of discussion, recognition of speakers, motions and voting.

4. Assist the Committee chair in leading informal consensus-building activities prior to and throughout all stages of the Reliability Standards development process.

5. Assist the Committee chair in reviewing all substitute or proxy representatives.

6. Duties of the Secretary. A member of the NERC staff shall serve under the direction of the SC officers as a non-voting secretary and has the responsibility to:

1. Conduct the day-to-day operation and business of the Committee.

2. Prepare, distribute and post notices of Committee meetings, record meeting proceedings, and prepare, distribute and post meeting minutes.

3. Maintain a record of all Committee proceedings, including responses, voting records, and correspondence.

4. Maintain Committee membership records.

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Section 6. Voting Members’ Expectations and Responsibilities

1. Committee voting members are expected to:

a. Contribute to the work and success of the Committee by facilitating the execution of the strategic vision and annual standards development work plan.

b. Be the applicable subject matter expertise representative of their industry sector to the Committee and represent their industry segment.

c. Be knowledgeable about Reliability Standards development activities.

d. Express their opinions and the opinions of their sector at Committee meetings.

e. Respond promptly to all Committee requests for attendance, reviews, comments and voting.

f. Assist in educating the industry on the Reliability Standards development process.

g. When a Committee member is unable to attend a Committee meeting, the member should notify the Secretary and identify a proxy as described under Section 8. Meetings, sub section 9. Proxies, infra. The member is expected to instruct the proxy on their role and responsibilities.

h. Duty of Care: SC members are to use due care and be diligent with respect to the management and administration of the affairs of NERC and the Standards Committee. This duty of care is generally thought to have two components: the time and attention devoted to NERC’s mission, and the skill and judgment reflected in the Committee’s decisions.

i. Duty of Loyalty: The duty of loyalty requires the Members to faithfully promote the mission of NERC and the Standard Committee, rather than his or her own or their entity’s interests. This duty includes compliance with NERC’s policies on conflicts of interest.

j. Duty to Adhere to High Ethical Standards: The duty to adhere to the applicable law and to high ethical standards requires that Standard Committee members, subcommittees, task forces and working groups devote themselves to assuring that they operate to further its stated objectives of NERC in compliance with legal requirements and high ethical standards.

Section 7. Executive Committee and Subcommittees

1. Executive Committee. The Committee shall have an Executive Committee that consists of five members, including the Committee officers and three at-large members, elected by the Standards Committee. The three at-large members cannot represent the same industry sectors that the Committee officers previously represented. The Executive Committee will be elected annually at the January Committee meeting. The Executive Committee shall meet when necessary between regularly scheduled Committee meetings to conduct

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Committee business, including delegated actions by the full Committee. Additionally, the Executive Committee shall have the authority to:

• Work with NERC staff to set agendas for Committee meetings.

• Act on behalf of the Committee to authorize postings of SARs, Reliability Standards, and other Standards-related documents.

• Provide advice and guidance to subcommittee chairs, as needed. 2. Additional Subcommittees, Task Forces, and ad hoc Working Groups. The

Committee has the authority to form subcommittees, task forces and ad hoc working groups as necessary.

Section 8. Meetings

1. Open Meetings. Meetings of the Committee shall be open to all interested parties who pre-register by the cut-off date included in the meeting announcement. Only voting members may act on items before the Committee. Meeting notices and agendas shall be publicly posted on the NERC website on the same day they are distributed to Committee members. Final minutes of Committee meetings shall be publicly posted on the NERC website the day after their approval by the Committee. Notices shall describe the purpose of meetings and shall identify a readily available source for further information about the meeting.

2. General Requirements. The Committee shall hold meetings as needed and may use conference calls or e-mail to conduct its business.

3. Notice. The Committee secretary shall announce its regularly scheduled meetings with a written notice (letter, facsimile, or e-mail) to all Committee members not less than ten nor more than sixty calendar days prior to the date of the meeting.

4. Agenda. The secretary shall provide an agenda with a written notice (letter, facsimile, or e-mail) for Committee meetings no less than five business days before a proposed meeting.

1. The agenda shall include, as necessary, background material for agenda items requiring a decision or vote. The agenda shall be posted on the NERC website the same day it is distributed to Committee members.

2. Items not in the agenda that require a vote cannot be added at a meeting without the unanimous consent of the members present. If such a matter comes up, it may also be deferred to the next meeting so that Committee members have time to consult with their industry segment members.

5. Parliamentary Procedures. In the absence of specific provisions in this scope document, the Committee shall conduct its meetings guided by the most recent edition of Robert’s Rules of Order, Newly Revised.

6. Quorum. A quorum requires two-thirds of the Committee voting members.

7. Voting. Voting may take place during regularly scheduled meetings or may take place through electronic means.

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1. Simple majority

2.

. Actions by the Committee shall be approved upon receipt of the affirmative vote of a majority of the members present and voting at a meeting at which quorum is present.

Recording votes

8. Actions without a Meeting. The Committee may act by mail or electronic (facsimile or e-mail) ballot without a regularly scheduled meeting. A majority of the members present and voting is required to approve any action. A quorum for actions without a meeting is two-thirds of the Committee members. The Committee chair or four members (each from different industry segments) may initiate the request for such action without a meeting. The secretary shall post a notice on the NERC website and shall provide Committee members with a written notice (letter, facsimile, or e-mail) of the subject matter for action not less than three business days prior to the date on which the action is to be voted. The secretary shall distribute a written notice to the Committee (letter, facsimile, or e-mail) of the results of such action within five business days following the vote and also post the notice on the NERC website. The secretary shall keep a record of all responses (e-mails, facsimiles, etc.) from the Committee members with the Committee minutes.

. Each individual member’s vote for each action taken shall be included in the minutes of each meeting.

9. Proxies. A member of the Committee is authorized to designate a proxy. Proxy representatives may attend and vote at Committee meetings provided the absent Committee member notifies in writing (letter, facsimile, or e-mail) the Committee chair, vice chair or secretary along with the reason(s) for the proxy. The member shall name the proxy representative and their affiliation in the correspondence. No member of the Committee can serve as a proxy for another member of the Committee. It is expected that the proxy will adhere to the Voting Members’ Expectations and Responsibilities as described in Section 6 of this document.

Item 6b

Plan for Conducting Five-Year Reviews Action Endorse the approach described below for conducting periodic reviews of standards as required by the NERC Standard Processes Manual, and the use of the proposed draft template to provide a record of the review. Approve soliciting nominations for subject matter experts for the groups of standards planned to be reviewed by the Reviews team as per the 2013-2015 Reliability Standards Development Plan. Preauthorize the Executive Committee to appoint teams of subject matter experts for Background The currently effective NERC Standard Processes Manual (Appendix 3A to the NERC Rules of Procedure) requires that:

Each reliability standard developed through NERC’s ANSI-accredited standards development process shall be reviewed at least once every five years from the effective date of the standard or the date of the latest Board of Trustees adoption to a revision of the standard, whichever is later.1

At the October 2012 Standards Committee meeting, an ad hoc team was formed to work with NERC staff to develop an approach to conducting these reviews. That team has prepared a template for use by teams of subject matter experts.

1 NERC Standard Processes Manual, posted at http://www.nerc.com/files/Appendix_3A_Standard_Processes_Manual_20110825.pdf, at page 41.

Unresolved Minority Issues There were a few minority issues raised by industry stakeholders that were not resolved. Issue: Some commenters questioned the use of the stakeholder process, arguing that

Order No. 762 did not mandate the use of the stakeholder process. Response: The SDT developed the revised footnote b using the Board-approved TPL-002-2b

standard as a starting point. FERC remanded the proposed standard because the process was not well defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand, and did not assure that BES reliability would be maintained. The SDT determined that more specificity around the stakeholder process would be directly responsive to the Commission’s concerns articulated in Order No. 672.

Issue: Some commenters questioned facets of the proposed TPL-001-2a standard that

were already approved by the ballot body and the NERC Board—specifically the application (or non application) of Note 12 for various planning events.

Response: The proposed TPL-001-2 reliability standard was approved by the ballot body in a

different standards development project, and then subsequently approved by the NERC Board. The Standard Authorization Request (SAR) for the footnote b project used that approval as the starting point to modify footnote b and Note 12.

Issue: A number of respondents raised jurisdictional concerns with the approach used in

footnote b, arguing that NERC is imposing itself into local planning processes in violation of its Section 215 authority.

Response: The SDT determined that the proposed footnote b preserves the role of local

regulatory authorities, while limited the role of the ERO in local planning process and still allowing the ERO to review possible Adverse Reliability Impacts. This is responsive to Order No. 762 directing that the ERO have oversight of any uses of the proposed footnote b in the planning process.

Additional Information A link to the project history and files is included here for reference: http://www.nerc.com/filez/standards/Assess-Transmission-Future-Needs.html

http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html

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Standards Authorization Request Form

Request to propose a new or a revision to a Reliability Standard

Title of Proposed Standard: Modification of MOD-010 through MOD-015

Date Submitted: 12/12/2012

SAR Requester Information

Name: John Simonelli, Chair, on behalf of the System Analysis and Modeling Subcommittee

Organization: System Analysis and Modeling Subcommittee

Telephone: 404-357-9843 E-mail: [email protected]

SAR Type (Check as many as applicable)

New Standard

Revision to existing Standard

Withdrawal of existing Standard

Urgent Action

SAR Information

Purpose (Describe what the standard action will achieve in support of Bulk Electric System reliability):

This SAR proposes modifying the current standards MOD-010 through MOD-015 by combining them into a fewer number of standards. This project will resolve FERC Order No. 693 directives relating to MOD-10 through MOD-15. The combined standards should be improved and strengthened to include additional requirements for the supply of data and models that specify the responsible functional entities, criteria for acceptability, standard formatting, and shareability. Short circuit data requirements should also be added to support the latest draft of the TPL-001-2 standard.

Industry Need (What is the industry problem this request is trying to solve?):

Models are the foundation of virtually all power system studies. Calculation of operating limits, planning studies for assessment of new generation and load growth, and performance assessments of system integrity protection schemes are but some of the studies that depend on accurate mathematical representations of transmission, generation, and load.

The current standards have several limitations in three broad categories that should be addressed:

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SAR Information

• Needed MOD standards are not approved o MOD-011, MOD-013, MOD-014 and MOD-015 were not approved by FERC Order No. 693

and remain in “pending” state due to their “fill-in-the-blank” nature, with requirements applicable to Regional Reliability Organizations (RROs).

o Approved standards MOD-010 and MOD-012 refer to specific modeling needs and processes outlined in unapproved standards MOD-011 and MOD-013 respectively.

• Approved MOD standards require clarification o The approved MOD standards lack clear delineation of responsibilities for providing and

receiving needed data and models. o The approved standards lack specificity. For example, the standards do not describe the

quality and usability that the provided models must have for static and dynamic conditions.

• The MOD standards should be strengthened o Newer Reliability Standards such as TPL-001-2 require a level of modeling not supported

by the approved MOD standards. o The approved standards do not support the increased modeling demands of new

technologies (e.g., renewable resources). o The absence of cogent modeling standards makes it difficult to identify the source of

emerging Interconnection-wide issues (such as declining frequency response), and to perform event analysis for large system disturbances.

Furthermore, the Power System Model Validation White Paper by the NERC Model Validation Task Force (MVTF) of the Transmission Issues Subcommittee (TIS) recommended that “The NERC MOD standards on powerflow and dynamics data (MOD-010 through MOD-015) should be improved and strengthened.”

Brief Description (Provide a paragraph that describes the scope of this standard action.)

1. The quantity of MOD standards should be reduced by combining the existing standards MOD-010 through MOD-015 into a fewer number of standards (such as one for steady state and one for dynamics).

2. Short Circuit Data requirements should be added to support the latest draft of the TPL standard (TPL-001-2).

3. Additions should be made to the requirements to supply data and models. a. The correct functional entities that are responsible to provide data and models or receive

them should be identified. References to the RRO as the applicable entity should be removed from any existing or new requirements.

b. Criteria for acceptability should be identified for supplied data and models. c. A standard format should be specified for supplied data.

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SAR Information

d. New technology model requirements should be included. e. Shareability of proprietary models should be addressed.

Detailed Description (Provide a description of the proposed project with sufficient details for the standard drafting team to execute the SAR. Also provide a justification for the development or revision of the standard, including an assessment of the reliability and market interface impacts of implementing or not implementing the standard action.)

All devices and equipment attached to the electric grid must be modeled to accurately capture how that equipment performs under static and dynamic conditions. There have been issues with proprietary models and the ability to share across sectors. Many generator manufacturers, notably wind turbine manufacturers, wish to keep the dynamics properties of their equipment confidential. As most areas are experiencing a surge in wind penetration, obtaining accurate dynamics model data for wind farms is becoming increasingly difficult, if not impossible. Similar challenges are also associated with modeling of utility-grade photovoltaic installations.

Generator Owners must provide accurate model data of their systems during the interconnection process. This information is critical to ensure that their power generating systems can be safely integrated into the electric grid. However, many of those accurate model datasets submitted for use in the interconnection process cannot be used for any other modeling endeavors due to non-disclosure agreements or pro forma tariff language concerning use of confidential information. These generator owners state that industry sensitive data is contained in their datasets and therefore cannot be divulged to anyone outside the interconnecting utility. This precludes use of those data and models in Interconnection-wide powerflow and dynamic analysis, which is crucial to understanding how the connecting equipment will interact with the rest of the system. Similar situations are arising with the models for wind turbines, photovoltaic inverters, and other power electronic devices.

When a number of proprietary models are excluded from system analysis, the interconnection-wide model becomes incomplete, and the potential interaction of equipment and their control systems is unknown. As such, there is no way to analyze the potential operating conditions of the interconnection.

Several improvements to MOD-010 through MOD-015 are outlined below. The standards development process will naturally need to consider parallel developments in other projects (such as Project 2007-09 Generator Verification) as well as requirements in other existing standards (such as IRO-010-1a and TOP-003-2). It may be desirable to move modeling requirements from other standards into the revised MOD standards. Furthermore, industry best practices and existing processes should be considered in the development of requirements, as many entities are successfully coordinating their efforts.

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SAR Information

1. Reduce the quantity of MOD Standards

MOD-010 through MOD-015 should be combined into a fewer number of standards, such as one standard for steady state and one for dynamics. However, it may also be useful to develop separate standards for equipment data collection (for the purpose of building needed steady-state and dynamic models) and the construction and validation of solved cases. MOD-011 and MOD-013 could be eliminated, but needed requirements from these standards should be moved into MOD-010 and MOD-012 respectively (or a comparable standard or set of standards).

MOD-010-0 clearly states that responsible entities (including Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners) must provide the needed steady state data and models in accordance with requirements that are provided in MOD-011-0. If MOD-011-0 is eliminated, then MOD-011-0 R1.1 through R1.7 must be included in a revised MOD-010 (or comparable standard). Further, a revised MOD-010 must include requirements for Planning Coordinators and Reliability Coordinators to provide the needed data, models and assembled cases to the Regional Entities and ERO (upon request or on a schedule) to facilitate the development of Interconnection-wide steady-state modeling cases.

MOD-012-0 contains requirements that responsible entities (including Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners) shall provide appropriate equipment characteristics, system data, and dynamics system modeling and simulation data in compliance with the respective Interconnection-wide requirements and reporting procedures. Further, the standard requires that the responsible entities must have evidence that they complied with the Interconnection-wide requirements and reporting procedures.

MOD-012-0 also states that the responsible entities (including Generator Owners) must provide the needed data and models in accordance with requirements that are provided in MOD-013. If MOD-013 is eliminated, then the specifics provided in MOD-013-1 R1.1, R1.2, R1.3, R1.4, and R1.5 must be included in MOD-012. Further, MOD-012 must include requirements for Planning Coordinators and Reliability Coordinators to provide the needed data, models and assembled cases to the Regional Entities and ERO (upon request or on a schedule) to facilitate the development of Interconnection-wide dynamics modeling cases.

A revised MOD-012 (or comparable standard) should account for the current MOD-013-1 provision that allows for responsible entities to provide estimated or typical manufacturer dynamics data based upon

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SAR Information

criteria provided in the Interconnection-wide procedures.1

A comparable provision should be included in a revised standard, but the requirements should be strengthened by specifying (and limiting) the instances when generic manufacturer data is accepted. For example, estimated or typical data could be accepted on a temporary basis, or upon documented agreement between entities when the impact is shown to be negligible; however, it is not possible to determine the impact without a sufficient model. A stronger, FERC-approved standard could ultimately resolve some of the issues associated with the use of generic manufacturer data for equipment, including wind turbines.

2. Add Short Circuit Data to MOD Standards

Short circuit analysis is required in the approved FAC-002-1 standard and the latest draft of the TPL-001-

2 standard.2

While the development of Interconnection-wide short-circuit modeling cases is not necessary and should not be required in a standard, the standards must require that neighboring entities share a sufficient level of short-circuit data to enable the studies required by the existing and future standards.

3. Add to the Requirement to Supply Data and Models a. Identify responsibility to provide and identify who is responsible to receive

A model of the power system requires data that includes but is not limited to: loads, transmission lines, transformers, shunt devices, generators, stacking order for dispatching generators, and interchanges of power. Such data must be supplied by various functional entities as shown in the table below. This data must be supplied to Planning Coordinators, Transmission Planners, Transmission Operators, and Reliability Coordinators as applicable. The Planning Coordinator or Transmission Planner should be responsible for putting all of the data together in a power flow case with associated dynamics data. These assembled cases should then be supplied to the Regional Entities and ERO, who can then combine cases to develop an Interconnection-wide case.

1 MOD-013-1 R1.2.1 states: “Estimated or typical manufacturer’s dynamics data, based on units of similar design

and characteristics, may be submitted when unit-specific dynamics data cannot be obtained. In no case shall other than unit-specific data be reported for generator units installed after 1990.”

2 See FAC-002-1 R1.1.4 and TPL-001-2 R2.3 & R2.8. See also page 209 in Project 2010-03 Modeling Data.

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SAR Information

Table 2: Data Responsibilities

Data

Responsible for Providing

Data & Models Delivers To

Load Forecast LSE PC, TP, TOP, RC

Transmission Data TO PC, TP, TOP, RC

Generator Data GO PC, TP, TOP, RC

a. Resource Projections

b. Generation stacking order RP PC, TP, TOP, RC

Interchange TSP, BA PC, TP, TOP, RC

Complete cases/models PC, TP ERO, RE

b. Identify acceptability

The present MOD standards provide little to no specification on whether a particular set of model data meets the requirements of the standards. The group recommends the following changes to the standards to identify acceptability:

• For powerflow models, the standards should specifically list all of the parameters which must be provided. For some parameters, it may be desirable to include established norms (for example, a typical range for transmission line impedance per mile at a given voltage). For these parameters, the data should either conform to established norms, or a statement attesting to unusual values should be provided. Data for new equipment should be tested in a standard library powerflow case by performing a solution to test convergence and reasonableness. Model data for a particular piece of equipment should be consistent across all applications that use that data. When available, the model data for the equipment should be from vendor-certified test reports or field tests. If a novel device is required to be represented by a user-written model, the standards should mandate that all of the equations describing the characteristics and logic of the model must be provided, along with any other descriptive information. Additionally, the data provided by asset owners needs to meet model validation standards such as MOD-026 and MOD-027 and any additional standards that arise from the work of the NERC Model Validation Working Group (MVWG).

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SAR Information

• For dynamics models, a standard, industry-recognized model name and a set of parameter values must be provided. If a standard, industry-recognized model is not available, the standards should specify that the asset owner must provide a block diagram, equations describing the characteristics of the model, values and names for all model parameters, and a list of all state variables. Furthermore, it should be required that, if a standard model is not available, the owner should develop the non-standard model in the format needed by the Transmission Planner or Planning Coordinator. The standards also need to specify that this information will be shared on an Interconnection-wide basis. Proprietary models with details hidden from the user (“black box” models) or those models that cannot be shared across the Interconnection are not acceptable.3

• The standards must also specify that the asset owner will provide models with additional detail and specificity to any Planning Coordinator upon request for its own internal studies.

Engineers performing power system studies need access to all of the model information in order to properly analyze the reliability and operating characteristics of the power system. To the extent practical, the revised MOD standards should include a list of specific data that is required. Preference should be given to IEEE standard models where such models are suitable representations of the equipment being modeled. Additionally, the data provided by asset owners needs to meet model validation standards such as MOD-026 and MOD-027 and any additional standards that arise from the work of the NERC MVWG.

c. Standard format

The specification and use of a standard format or set of formats enables data to be exchanged easily between involved entities (e.g., PCs, TPs, TOPs, RCs, TOs, GOs, LSEs, RPs) and helps support the accurate development of steady state, short circuit, and dynamic base cases. Having a standard format allows the development and aggregation of base cases which cover large areas such as the four Interconnections in North America. Each vendor has their own data format, some of which are translatable between vendors. However, some translations are only useful for steady-state analysis. Dynamics data does not translate well between vendors.

The MOD standards should incorporate industry standard formats for all steady-state, short-circuit, and dynamics data, and the standard formats should be approved via the NERC standard development process. A translation of a specific vendor format to the common format is acceptable provided the resulting data has been validated.

3 As noted in Section 1 and footnote 1, concessions could be considered for the acceptance of generic

manufacturer data, if proven to be working and useful, based on whether it is used on a temporary basis or when the impact is shown to be negligible, for example.

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SAR Information

NERC should lead the development of test cases to validate the translation of the vendor format to the common format. If a specific vendor format is not translatable to the approved common format then it does not comply with the standard. Coding for generic block diagrams should be included. The NERC Model Validation Working Group also recommends standardizing data exchange formats.

d. How to deal with new technology (require a user-written model if no standard model exists)

Presently, models for new technology equipment are introduced in a non-uniform manner. Equipment manufacturers and other outside interests have internally created a proliferation of non-standard equipment models. These models thus lack sufficient input from the individuals who study reliability and operating characteristics of the power system. These models were inserted into production studies without vetting from recognized technical authorities such as the IEEE. Many of these models are proprietary and distributed as “black box” object code modules for specific simulation programs.

Models for new technology must include information comparable to existing models in common use. Powerflow models need to include the equations describing the characteristics of the equipment being modeled. For dynamics, a block diagram is essential. Ideally, the industry should collaboratively develop model structures which include those elements that are of importance in power system studies. Such an effort would enable consistent development of useful models while simultaneously protecting manufacturer interests regarding confidential trade secrets of implementation details that are not relevant to power system studies. Equipment should not be allowed to connect to the grid if the models lack the information needed for performing appropriate reliability and operating characteristics assessments. All responsible entities including Transmission Owners and Generator Owners must be held accountable for providing the information needed to maintain power system reliability.

e. Shareability (an issue tangential to the MOD standards)

One of the problems identified in the Power System Model Validation White Paper is that there are legal and procedural issues that inhibit the gathering and distribution of model data among stakeholders. The report cites FERC CEII (critical energy infrastructure information) requirements and proprietary issues that result in claims of the need for confidentially.

The report noted that in particular, Generator Owners of wind turbines are unable to provide unit specific data due to wind turbine manufacturer statements that the dynamics models of their equipment must be held confidential. This is particularly problematic in areas that are experiencing a surge in wind penetration.

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SAR Information

One possible approach to address proprietary model issues is for the Generator Owner to work with the vendor to develop a generic model that can be shared across the Interconnection. In such a case, the standard should specify that the Generator Owner is responsible for reviewing and submitting supporting simulations performed by the vendor that demonstrate and certify a provided generic model will accurately simulate the generator (or any other device in question) for system level studies. The Generator Owner must also arrange to give the proprietary model to the Transmission Planner, Planning Coordinator, and Reliability Coordinator for their sole use, using an NDA if necessary.

Another approach is for NERC and/or FERC to hold a technical conference where wind turbine manufacturers will be asked to give explanations for keeping their models proprietary while NERC staff and members of NERC subcommittees describe why detailed models are required. Following such a technical conference, NERC and FERC could consider subsequent steps that could result in a FERC Notice of Inquiry or Notice of Proposed Rulemaking on the subject.

Reliability Functions

The Standard will Apply to the Following Functions (Check each one that applies.)

Regional Reliability Organization

Conducts the regional activities related to planning and operations, and coordinates activities of Responsible Entities to secure the reliability of the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator Responsible for the real-time operating reliability of its Reliability Coordinator Area in coordination with its neighboring Reliability Coordinator’s wide area view.

Balancing Authority Integrates resource plans ahead of time, and maintains load-interchange-resource balance within a Balancing Authority Area and supports Interconnection frequency in real time.

Interchange Authority Ensures communication of interchange transactions for reliability evaluation purposes and coordinates implementation of valid and balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner Develops a >one year plan for the resource adequacy of its specific loads within a Planning Coordinator area.

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Reliability Functions

Transmission Planner Develops a >one year plan for the reliability of the interconnected Bulk Electric System within its portion of the Planning Coordinator area.

Transmission Service Provider

Administers the transmission tariff and provides transmission services under applicable transmission service agreements (e.g., the pro forma tariff).

Transmission Owner Owns and maintains transmission facilities.

Transmission Operator

Ensures the real-time operating reliability of the transmission assets within a Transmission Operator Area.

Distribution Provider Delivers electrical energy to the End-use customer.

Generator Owner Owns and maintains generation facilities.

Generator Operator Operates generation unit(s) to provide real and Reactive Power.

Purchasing-Selling Entity

Purchases or sells energy, capacity, and necessary reliability-related services as required.

Market Operator Interface point for reliability functions with commercial functions.

Load-Serving Entity Secures energy and transmission service (and reliability-related services) to serve the End-use Customer.

Reliability and Market Interface Principles

Applicable Reliability Principles (Check all that apply).

1. Interconnected bulk power systems shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the NERC Standards.

2. The frequency and voltage of interconnected bulk power systems shall be controlled within defined limits through the balancing of real and Reactive Power supply and demand.

3. Information necessary for the planning and operation of interconnected bulk power systems

shall be made available to those entities responsible for planning and operating the systems reliably.

4. Plans for emergency operation and system restoration of interconnected bulk power systems shall be developed, coordinated, maintained and implemented.

5. Facilities for communication, monitoring and control shall be provided, used and maintained for the reliability of interconnected bulk power systems.

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Reliability and Market Interface Principles

6. Personnel responsible for planning and operating interconnected bulk power systems shall be trained, qualified, and have the responsibility and authority to implement actions.

7. The security of the interconnected bulk power systems shall be assessed, monitored and maintained on a wide area basis.

8. Bulk power systems shall be protected from malicious physical or cyber attacks.

Does the proposed Standard comply with all of the following Market Interface Principles?

Enter

(yes/no)

1. A reliability standard shall not give any market participant an unfair competitive advantage.

Yes

2. A reliability standard shall neither mandate nor prohibit any specific market structure.

Yes

3. A reliability standard shall not preclude market solutions to achieving compliance with that standard.

Yes

4. A reliability standard shall not require the public disclosure of commercially sensitive information. All market participants shall have equal opportunity to access commercially non-sensitive information that is required for compliance with reliability standards.

Yes

Related Standards

Standard No. Explanation

IRO-010-1a Identifies the high-level process that must be followed to ensure that RCs are provided with models. This standard could be considered for consolidation into revised MOD standards.

TOP-003-2 Identifies the high-level process that must be followed to ensure that BAs and TOPs are provided with models. This standard could be considered for consolidation into revised MOD standards.

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Related SARs

SAR ID Explanation

Regional Variances

Region Explanation

ERCOT

FRCC

MRO

NPCC

RFC

SERC

SPP

WECC

Standard Authorization Request Form

Supplemental SAR for Project 2010-13.2 Relay Loadability Order 733 Phase 2 (Relay Loadability: Generation)

Request Date 11/30/2012

SC Approval Date TBD

Revised Date

SAR Requester Information SAR Type (Check a box for each one that applies.)

Name

Howard Gugel, Director of Standards Development

New Standard

Primary Contact

Scott Barfield-McGinnis, Standards Developer

Revision to existing Standard

Telephone 404-446-9689

Fax

Withdrawal of existing Standard

E-mail [email protected] Urgent Action

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Project 2010-13.2 – Relay Loadability Order 733, (Draft 1) Supplemental Standard Authorization Request (Revision to PRC-023-2) 2

Purpose Prevent a potential compliance overlap with the current Reliability Standard PRC-023-2 – Transmission Relay Loadability, which became effective July 1, 2012. The overlap would be created when the proposed PRC-025-1 – Generator Relay Loadability, which is currently under development, is approved and becomes effective.

Industry Need

The generator relay loadability standard drafting team identified conditions in the development of the drafting of the PRC-025-1 standard that would create the potential for overlap (e.g., “double jeopardy”) and confusion as to which standard is applicable to the Generator Owner entity (i.e., PRC-023-2 or PRC-025-1).

Brief Description This request includes modifying PRC-023-2 to add clarity to the Applicability section of the PRC-023-2 standard. Other modifications include updating references from the version number to reflect the new version number. Detail regarding the effective dates may be removed as the new version is anticipated to become approved beyond the implementation plan for the current version. Detailed Description

The generator relay loadability standard drafting team (GENRLOSDT) continues to evaluate the best alternative to modifying PRC-023-2 to clarify the Generator Owner’s applicability with regard to load-responsive protective relays. The drafting team has provided a redline draft to PRC-023-2 with a proposed solution to the issue; however, the drafting team recognizes that the draft PRC-025-1 may provide the opportunity to remove the Generator Owner from PRC-023-2 and therefore eliminate the overlap and confusion without creating a gap in reliability.

The drafting team considered whether changes would be necessary to Requirement R1, criterion 6 and decided it should remain in the standard as there may be cases where PRC-023 will be applicable to lines that connect generation stations remote to load. The drafting team has not revealed any concerns about this criterion in relation to the proposed PRC-025-1 standard currently being drafted.

The effective date of the draft PRC-023-3 is anticipated to occur beyond the Implementation Plan approved in version two; therefore, the effective date tables are proposed for removal. If an interim implementation is required to bridge PRC-023-2 to the next version, the standard drafting team will modify the effective date tables accordingly.

A complete review of the standard will be conducted to reveal any editorial edits that may be needed to improve the quality of the Reliability Standard.

Industry commenting, balloting, and approval of the revisions to the draft PRC-023-3 standard will occur contemporaneously with the drafting of the proposed PRC-025-1 standard. Adoption of PRC-023-3 will contingent upon PRC-025-1.

Project 2010-13.2 – Relay Loadability Order 733, (Draft 1) Supplemental Standard Authorization Request (Revision to PRC-023-2) 3

Reliability Functions The Standard will Apply to the Following Functions (Check box for each one that applies.)

Responsible for the real-time operating reliability of its Reliability Coordinator Area in coordination with its neighboring Reliability Coordinator’s wide area view.

Reliability Coordinator

Balancing Authority

Integrates resource plans ahead of time, and maintains load-interchange-resource balance within a Balancing Authority Area and supports Interconnection frequency in real time.

Interchange Authority

Ensures communication of interchange transactions for reliability evaluation purposes and coordinates implementation of valid and balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads within

its portion of the Planning Coordinator’s Area. Transmission Owner

Owns and maintains transmission facilities.

Transmission Operator

Ensures the real-time operating reliability of the transmission assets within a Transmission Operator Area.

Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk Electric System within the Transmission Planner Area.

Transmission Service Provider

Administers the transmission tariff and provides transmission services under applicable transmission service agreements (e.g., the pro forma tariff).

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling Entity

Purchases or sells energy, capacity, and necessary reliability-related services as required. Secures energy and transmission service (and reliability-related services) to serve the End-use Customer.

Load-Serving Entity

Project 2010-13.2 – Relay Loadability Order 733, (Draft 1) Supplemental Standard Authorization Request (Revision to PRC-023-2) 4

Reliability and Market Interface Principles Applicable Reliability Principles (Check box for all that apply.)

1.

Interconnected bulk power systems shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the NERC Standards.

2.

The frequency and voltage of interconnected bulk power systems shall be controlled within defined limits through the balancing of real and reactive power supply and demand.

3.

Information necessary for the planning and operation of interconnected bulk power systems shall be made available to those entities responsible for planning and operating the systems reliably.

4.

Plans for emergency operation and system restoration of interconnected bulk power systems shall be developed, coordinated, maintained and implemented.

5.

Facilities for communication, monitoring and control shall be provided, used and maintained for the reliability of interconnected bulk power systems.

6.

Personnel responsible for planning and operating interconnected bulk power systems shall be trained, qualified, and have the responsibility and authority to implement actions.

7.

The security of the interconnected bulk power systems shall be assessed, monitored and maintained on a wide area basis.

8. Bulk power systems shall be protected from malicious physical or cyber attacks.

Does the proposed Standard comply with all of the following Market Interface Principles?

1.

(Select ‘yes’ or ‘no’ from the drop-down box.)

2.

A reliability standard shall not give any market participant an unfair competitive advantage. Yes

3.

A reliability standard shall neither mandate nor prohibit any specific market structure. Yes

4.

A reliability standard shall not preclude market solutions to achieving compliance with that standard. Yes

A reliability standard shall not require the public disclosure of commercially sensitive information. All market participants shall have equal opportunity to access commercially non-sensitive information that is required for compliance with reliability standards. Yes

Project 2010-13.2 – Relay Loadability Order 733, (Draft 1) Supplemental Standard Authorization Request (Revision to PRC-023-2) 5

Related Standards Standard No. Explanation

None.

Related SARs SAR ID Explanation

Regional Variances Region Explanation

ERCOT None.

FRCC None.

MRO None.

NPCC None.

RFC None.

SERC None.

SPP None.

WECC

None.

Standard PRC-023-23 — Transmission Relay Loadability

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A. Introduction 1. Title: Transmission Relay Loadability

2. Number: PRC-023-23

3. Purpose: Protective relay settings shall not limit transmission loadability; not interfere with system operators’ ability to take remedial action to protect system reliability and; be set to reliably detect all fault conditions and protect the electrical network from these faults.

4. Applicability

4.1. Functional Entity

4.1.1 Transmission Owners with load-responsive phase protection systems as described in PRC-023-23 - Attachment A, applied toat the terminals of the circuits defined in 4.2.1 (Circuits Subject to Requirements R1 – R5).

4.1.2 Generator Owners with load-responsive phase protection systems as described in PRC-023-2 - Attachment A, applied toat the terminals of the circuits defined in 4.2.1 (Circuits Subject to Requirements R1 – R5).

4.1.3 Distribution Providers with load-responsive phase protection systems as described in PRC-023-23 - Attachment A, applied toat the terminals of the circuits defined in 4.2.1 (Circuits Subject to Requirements R1 – R5), provided those circuits have bi-directional flow capabilities.

4.1.4 Planning Coordinators

4.2. Circuits

4.2.1 Circuits Subject to Requirements R1 – R5

4.2.1.1 Transmission lines operated at 200 kV and above.

4.2.1.2 Transmission lines operated at 100 kV to 200 kV selected by the Planning Coordinator in accordance with R6.

4.2.1.3 Transmission lines operated below 100 kV that are part of the BES and selected by the Planning Coordinator in accordance with R6.

4.2.1.4 Transformers with low voltage terminals connected at 200 kV and above.

4.2.1.5 Transformers with low voltage terminals connected at 100 kV to 200 kV selected by the Planning Coordinator in accordance with R6.

4.2.1.6 Transformers with low voltage terminals connected below 100 kV that are part of the BES and selected by the Planning Coordinator in accordance with R6.

4.2.2 Circuits Subject to Requirement R6

4.2.2.1 Transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals connected at 100 kV to 200 kV

4.2.2.2 Transmission lines operated below100below 100 kV and transformers with low voltage terminals connected below 100 kV that are part of the BES

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Standard PRC-023-23 — Transmission Relay Loadability

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5. Effective Dates

The effective dates of the requirements in the PRC-023-2 standard corresponding to the applicable Functional Entities and circuits are summarized in the following table:

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Requirement Applicability

Effective Date

Jurisdictions where Regulatory Approval is

Required

Jurisdictions where No Regulatory

Approval is Required

R1

Each Transmission Owner, Generator Owner, and Distribution Provider with transmission lines operating at 200 kV and above and transformers with low voltage terminals connected at 200 kV and above, except as noted below.

First day of the first calendar quarter, after applicable regulatory approvals

First calendar quarter after Board of Trustees adoption

• For Requirement R1, criterion 10.1, to set transformer fault protection relays on transmission lines terminated only with a transformer such that the protection settings do not expose the transformer to fault level and duration that exceeds its mechanical withstand capability

First day of the first calendar quarter 12 months after applicable regulatory approvals

First day of the first calendar quarter 12 months after Board of Trustees adoption

• For supervisory elements as described in PRC-023-2 - Attachment A, Section 1.6

First day of the first calendar quarter 24 months after applicable regulatory approvals

First day of the first calendar quarter 24 months after Board of Trustees adoption

• For switch-on-to-fault schemes as described in PRC-023-2 - Attachment A, Section 1.3

Later of the first day of the first calendar quarter after applicable regulatory approvals of PRC-023-2 or the first day of the first calendar quarter 39 months following applicable regulatory approvals of PRC-023-1 (October 1, 2013)

Later of the first day of the first calendar quarter after Board of Trustees adoption of PRC-023-2 or July 1, 20111

Each Transmission Owner, Generator Owner, and Distribution Provider with circuits identified by the Planning Coordinator pursuant to Requirement R6

Later of the first day of the first calendar quarter 39 months following notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2 per

Later of the first day of the first calendar quarter 39 months following notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2

1 July 1, 2011 is the first day of the first calendar quarter 39 months following the Board of Trustees February 12, 2008 approval of PRC-023-1.

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Requirement Applicability

Effective Date

Jurisdictions where Regulatory Approval is

Required

Jurisdictions where No Regulatory

Approval is Required

application of Attachment B, or the first day of the first calendar year in which any criterion in Attachment B applies, unless the Planning Coordinator removes the circuit from the list before the applicable effective date

per application of Attachment B, or the first day of the first calendar year in which any criterion in Attachment B applies, unless the Planning Coordinator removes the circuit from the list before the applicable effective date

R2 and R3

Each Transmission Owner, Generator Owner, and Distribution Provider with transmission lines operating at 200 kV and above and transformers with low voltage terminals connected at 200 kV and above

First day of the first calendar quarter after applicable regulatory approvals

First day of the first calendar quarter after Board of Trustees adoption

Each Transmission Owner, Generator Owner, and Distribution Provider with circuits identified by the Planning Coordinator pursuant to Requirement R6

Later of the first day of the first calendar quarter 39 months following notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of Attachment B, or the first day of the first calendar year in which any criterion in Attachment B applies, unless the Planning Coordinator removes the circuit from the list before the applicable effective date

Later of the first day of the first calendar quarter 39 months following notification by the Planning Coordinator of a circuit’s inclusion on a list of circuits subject to PRC-023-2 per application of Attachment B, or the first day of the first calendar year in which any criterion in Attachment B applies, unless the Planning Coordinator removes the circuit from the list before the applicable effective date

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Requirement Applicability

Effective Date

Jurisdictions where Regulatory Approval is

Required

Jurisdictions where No Regulatory

Approval is Required

R4 Each Transmission Owner, Generator Owner, and Distribution Provider that chooses to use Requirement R1 criterion 2 as the basis for verifying transmission line relay loadability

First day of the first calendar quarter six months after applicable regulatory approvals

First day of the first calendar quarter six months after Board of Trustees adoption

R5 Each Transmission Owner, Generator Owner, and Distribution Provider that sets transmission line relays according to Requirement R1 criterion 12

First day of the first calendar quarter six months after applicable regulatory approvals

First day of the first calendar quarter six months after Board of Trustees adoption

R6 Each Planning Coordinator shall conduct an assessment by applying the criteria in Attachment B to determine the circuits in its Planning Coordinator area for which Transmission Owners, Generator Owners, and Distribution Providers must comply with Requirements R1 through R5

First day of the first calendar quarter 18 months after applicable regulatory approvals

First day of the first calendar quarter 18 months after Board of Trustees adoption

Standard PRC-023-23 — Transmission Relay Loadability

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First day of the first calendar quarter beyond the date that this standard is approved by applicable regulatory authorities, or in those jurisdictions where regulatory approval is not required, the standard becomes effective on the first day of the first calendar quarter beyond the date this standard is approved by the NERC Board of Trustees, or as otherwise made effective pursuant to the laws applicable to such ERO governmental authorities.

B. Requirements R1. Each Transmission Owner, Generator Owner, and Distribution Provider shall use any one of the

following criteria (Requirement R1, criteria 1 through 13) for any specific circuit terminal to prevent its phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the BES for all fault conditions. Each Transmission Owner, Generator Owner, and Distribution Provider shall evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees. [Violation Risk Factor: High] [Time Horizon: Long Term Planning].

Criteria:

1. Set transmission line relays so they do not operate at or below 150% of the highest seasonal Facility Rating of a circuit, for the available defined loading duration nearest 4 hours (expressed in amperes).

2. Set transmission line relays so they do not operate at or below 115% of the highest seasonal 15-minute Facility Rating2

3. Set transmission line relays so they do not operate at or below 115% of the maximum theoretical power transfer capability (using a 90-degree angle between the sending-end and receiving-end voltages and either reactance or complex impedance) of the circuit (expressed in amperes) using one of the following to perform the power transfer calculation:

of a circuit (expressed in amperes).

• An infinite source (zero source impedance) with a 1.00 per unit bus voltage at each end of the line.

• An impedance at each end of the line, which reflects the actual system source impedance with a 1.05 per unit voltage behind each source impedance.

4. Set transmission line relays on series compensated transmission lines so they do not operate at or below the maximum power transfer capability of the line, determined as the greater of:

• 115% of the highest emergency rating of the series capacitor.

• 115% of the maximum power transfer capability of the circuit (expressed in amperes), calculated in accordance with Requirement R1, criterion 3, using the full line inductive reactance.

5. Set transmission line relays on weak source systems so they do not operate at or below 170% of the maximum end-of-line three-phase fault magnitude (expressed in amperes).

6. Set transmission line relays applied on transmission lines connected to generation stations remote to load so they do not operate at or below 230% of the aggregated generation nameplate capability.

2 When a 15-minute rating has been calculated and published for use in real-time operations, the 15-minute rating can be used to establish the loadability requirement for the protective relays.

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7. Set transmission line relays applied at the load center terminal, remote from generation stations, so they do not operate at or below 115% of the maximum current flow from the load to the generation source under any system configuration.

8. Set transmission line relays applied on the bulk system-end of transmission lines that serve load remote to the system so they do not operate at or below 115% of the maximum current flow from the system to the load under any system configuration.

9. Set transmission line relays applied on the load-end of transmission lines that serve load remote to the bulk system so they do not operate at or below 115% of the maximum current flow from the load to the system under any system configuration.

10. Set transformer fault protection relays and transmission line relays on transmission lines terminated only with a transformer so that the relays do not operate at or below the greater of:

• 150% of the applicable maximum transformer nameplate rating (expressed in amperes), including the forced cooled ratings corresponding to all installed supplemental cooling equipment.

• 115% of the highest operator established emergency transformer rating

10.1 Set load responsive transformer fault protection relays, if used, such that the protection settings do not expose the transformer to a fault level and duration that exceeds the transformer’s mechanical withstand capability3

11. For transformer overload protection relays that do not comply with the loadability component of Requirement R1, criterion 10 set the relays according to one of the following:

.

• Set the relays to allow the transformer to be operated at an overload level of at least 150% of the maximum applicable nameplate rating, or 115% of the highest operator established emergency transformer rating, whichever is greater, for at least 15 minutes to provide time for the operator to take controlled action to relieve the overload.

• Install supervision for the relays using either a top oil or simulated winding hot spot temperature element set no less than 100° C for the top oil temperature or no less than 140° C for the winding hot spot temperature4

12. When the desired transmission line capability is limited by the requirement to adequately protect the transmission line, set the transmission line distance relays to a maximum of 125% of the apparent impedance (at the impedance angle of the transmission line) subject to the following constraints:

.

a. Set the maximum torque angle (MTA) to 90 degrees or the highest supported by the manufacturer.

b. Evaluate the relay loadability in amperes at the relay trip point at 0.85 per unit voltage and a power factor angle of 30 degrees.

3 As illustrated by the “dotted line” in IEEE C57.109-1993 - IEEE Guide for Liquid-Immersed Transformer Through-Fault-Current Duration, Clause 4.4, Figure 4

4 IEEE standard C57.91, Tables 7 and 8, specify that transformers are to be designed to withstand a winding hot spot temperature of 180 degrees C, and Annex A cautions that bubble formation may occur above 140 degrees C.

Standard PRC-023-23 — Transmission Relay Loadability

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c. Include a relay setting component of 87% of the current calculated in Requirement R1, criterion 12 in the Facility Rating determination for the circuit.

13. Where other situations present practical limitations on circuit capability, set the phase protection relays so they do not operate at or below 115% of such limitations.

R2. Each Transmission Owner, Generator Owner, and Distribution Provider shall set its out-of-step blocking elements to allow tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per Requirement R1. [Violation Risk Factor: High] [Time Horizon: Long Term Planning]

R3. Each Transmission Owner, Generator Owner, and Distribution Provider that uses a circuit capability with the practical limitations described in Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall use the calculated circuit capability as the Facility Rating of the circuit and shall obtain the agreement of the Planning Coordinator, Transmission Operator, and Reliability Coordinator with the calculated circuit capability. [Violation Risk Factor: Medium] [Time Horizon: Long Term Planning]

R4. Each Transmission Owner, Generator Owner, and Distribution Provider that chooses to use Requirement R1 criterion 2 as the basis for verifying transmission line relay loadability shall provide its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an updated list of circuits associated with those transmission line relays at least once each calendar year, with no more than 15 months between reports. [Violation Risk Factor: Lower] [Time Horizon: Long Term Planning]

R5. Each Transmission Owner, Generator Owner, and Distribution Provider that sets transmission line relays according to Requirement R1 criterion 12 shall provide an updated list of the circuits associated with those relays to its Regional Entity at least once each calendar year, with no more than 15 months between reports, to allow the ERO to compile a list of all circuits that have protective relay settings that limit circuit capability. [Violation Risk Factor: Lower] [Time Horizon: Long Term Planning]

R6. Each Planning Coordinator shall conduct an assessment at least once each calendar year, with no more than 15 months between assessments, by applying the criteria in PRC-023-3, Attachment B to determine the circuits in its Planning Coordinator area for which Transmission Owners, Generator Owners, and Distribution Providers must comply with Requirements R1 through R5. The Planning Coordinator shall: [Violation Risk Factor: High] [Time Horizon: Long Term Planning]

6.1 Maintain a list of circuits subject to PRC-023-23 per application of Attachment B, including identification of the first calendar year in which any criterion in PRC-023-3, Attachment B applies.

6.2 Provide the list of circuits to all Regional Entities, Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area within 30 calendar days of the establishment of the initial list and within 30 calendar days of any changes to that list.

C. Measures M1. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence

such as spreadsheets or summaries of calculations to show that each of its transmission relays is set according to one of the criteria in Requirement R1, criterion 1 through 13 and shall have evidence such as coordination curves or summaries of calculations that show that relays set per criterion 10 do not expose the transformer to fault levels and durations beyond those indicated in the standard. (R1)

Standard PRC-023-23 — Transmission Relay Loadability

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M2. Each Transmission Owner, Generator Owner, and Distribution Provider shall have evidence such as spreadsheets or summaries of calculations to show that each of its out-of-step blocking elements is set to allow tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per Requirement R1. (R2)

M3. Each Transmission Owner, Generator Owner, and Distribution Provider with transmission relays set according to Requirement R1, criterion 6, 7, 8, 9, 12, or 13 shall have evidence such as Facility Rating spreadsheets or Facility Rating database to show that it used the calculated circuit capability as the Facility Rating of the circuit and evidence such as dated correspondence that the resulting Facility Rating was agreed to by its associated Planning Coordinator, Transmission Operator, and Reliability Coordinator. (R3)

M4. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission line relays according to Requirement R1, criterion 2 shall have evidence such as dated correspondence to show that it provided its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an updated list of circuits associated with those transmission line relays within the required timeframe. The updated list may either be a full list, a list of incremental changes to the previous list, or a statement that there are no changes to the previous list. (R4)

M5. Each Transmission Owner, Generator Owner, or Distribution Provider that sets transmission line relays according to Requirement R1, criterion 12 shall have evidence such as dated correspondence that it provided an updated list of the circuits associated with those relays to its Regional Entity within the required timeframe. The updated list may either be a full list, a list of incremental changes to the previous list, or a statement that there are no changes to the previous list. (R5)

M6. Each Planning Coordinator shall have evidence such as power flow results, calculation summaries, or study reports that it used the criteria established within PRC-023-3, Attachment B to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard as described in Requirement R6. The Planning Coordinator shall have a dated list of such circuits and shall have evidence such as dated correspondence that it provided the list to the Regional Entities, Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area within the required timeframe.

D. Compliance 1. Compliance Monitoring Process

1.1. Compliance Monitoring Responsibility

• For entities that do not work for the Regional Entity, the Regional Entity shall serve as the Compliance Enforcement Authority.

• For functional entities that work for their Regional Entity, the ERO shall serve as the Compliance Enforcement Authority.

1.2. Data Retention

The Transmission Owner, Generator Owner, Distribution Provider and Planning Coordinator shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation:

Standard PRC-023-23 — Transmission Relay Loadability

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The Transmission Owner, Generator Owner, and Distribution Provider shall each retain documentation to demonstrate compliance with Requirements R1 through R5 for three calendar years.

The Planning Coordinator shall retain documentation of the most recent review process required in R6. The Planning Coordinator shall retain the most recent list of circuits in its Planning Coordinator area for which applicable entities must comply with the standard, as determined per R6.

If a Transmission Owner, Generator Owner, Distribution Provider, or Planning Coordinator is found non-compliant, it shall keep information related to the non-compliance until found compliant or for the time specified above, whichever is longer.

The Compliance MonitorEnforcement Authority shall keep the last audit record and all requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Assessment Processes

• Compliance Audit

• Self-Certification

• Spot Checking

• Compliance Violation Investigation

• Self-Reporting

• Complaint

1.4. Additional Compliance Information

None.

Standard PRC-023-23 — Transmission Relay Loadability

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2. Violation Severity Levels:

Requirement Lower Moderate High Severe

R1 N/A N/A N/A

The responsible entity did not use any one of the following criteria (Requirement R1 criterion 1 through 13) for any specific circuit terminal to prevent its phase protective relay settings from limiting transmission system loadability while maintaining reliable protection of the Bulk Electric System for all fault conditions.

OR

The responsible entity did not evaluate relay loadability at 0.85 per unit voltage and a power factor angle of 30 degrees.

R2 N/A N/A N/A

The responsible entity failed to ensure that its out-of-step blocking elements allowed tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability per Requirement R1.

R3 N/A N/A N/A

The responsible entity that uses a circuit capability with the practical limitations described in Requirement R1 criterion 6, 7, 8, 9, 12, or 13 did not use the calculated circuit capability as the Facility Rating of the circuit.

Standard PRC-023-23 — Transmission Relay Loadability

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Requirement Lower Moderate High Severe

OR

The responsible entity did not obtain the agreement of the Planning Coordinator, Transmission Operator, and Reliability Coordinator with the calculated circuit capability.

R4 N/A N/A N/A

The responsible entity did not provide its Planning Coordinator, Transmission Operator, and Reliability Coordinator with an updated list of circuits that have transmission line relays set according to the criteria established in Requirement R1 criterion 2 at least once each calendar year, with no more than 15 months between reports.

R5 N/A N/A N/A

The responsible entity did not provide its Regional Entity, with an updated list of circuits that have transmission line relays set according to the criteria established in Requirement R1 criterion 12 at least once each calendar year, with no more than 15 months between reports.

R6 N/A

The Planning Coordinator used the criteria established within Attachment B to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met parts 6.1 and 6.2, but more

The Planning Coordinator used the criteria established within Attachment B to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met parts 6.1 and 6.2, but 24

The Planning Coordinator failed to use the criteria established within Attachment B to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard.

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Requirement Lower Moderate High Severe

than 15 months and less than 24 months lapsed between assessments.

OR

The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met 6.1 and 6.2 but failed to include the calendar year in which any criterion in Attachment B first applies.

OR

The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met 6.1 and 6.2 but provided the list of circuits to the Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area between 31 days and 45 days after the list was established or updated.

months or more lapsed between assessments.

OR

The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard and met 6.1 and 6.2 but provided the list of circuits to the Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area between 46 days and 60 days after list was established or updated. (part 6.2)

OR

The Planning Coordinator used the criteria established within Attachment B, at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard but failed to meet parts 6.1 and 6.2.

OR

The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard but failed to maintain the list of circuits determined according to the process described in Requirement R6. (part 6.1)

OR

The Planning Coordinator used the criteria established within Attachment B at least once each calendar year, with no more than 15 months between assessments to determine the circuits in its Planning Coordinator area for which applicable entities must

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Requirement Lower Moderate High Severe

(part 6.2) comply with the standard and met 6.1 but failed to provide the list of circuits to the Reliability Coordinators, Transmission Owners, Generator Owners, and Distribution Providers within its Planning Coordinator area or provided the list more than 60 days after the list was established or updated. (part 6.2)

OR

The Planning Coordinator failed to determine the circuits in its Planning Coordinator area for which applicable entities must comply with the standard.

Standard PRC-023-23 — Transmission Relay Loadability

E. Regional Differences None.

F. Supplemental Technical Reference Document 1. The following document is an explanatory supplement to the standard. It provides the technical

rationale underlying the requirements in this standard. The reference document contains methodology examples for illustration purposes it does not preclude other technically comparable methodologies.

“Determination and Application of Practical Relaying Loadability Ratings,” Version 1.0, June 2008, prepared by the System Protection and Control Task Force of the NERC Planning Committee, available at: http://www.nerc.com/fileUploads/File/Standards/Relay_Loadability_Reference_Doc_Clean_Final_2008July3.pdf

.

Version History

Version Date Action Change Tracking 1 February 12, 2008 Approved by Board of Trustees New

1 March 19, 2008 Corrected typo in last sentence of Severe VSL for Requirement 3 — “then” should be “than.”

Errata

1 March 18, 2010 Approved by FERC

1 Filed for approval April 19, 2010

Changed VRF for R3 from Medium to High; changed VSLs for R1, R2, R3 to binary Severe to comply with Order 733

Revision

2 March 10, 2011 approved by Board of Trustees

Revised to address initial set of directives from Order 733

Revision (Project 2010-13)

2 March 15, 2012 FERC order issued approving PRC-023-2 (approval becomes effective May 7, 2012)

3 TBD Clarify applicability for consistency with PRC-025-1 and other minor corrections

Supplemental SAR (Project 2010-13.2)

Standard PRC-023-23 — Transmission Relay Loadability

PRC-023-3 — Attachment A 1. This standard includes any protective functions which could trip with or without time delay, on load

current, including but not limited to:

1.1. Phase distance.

1.2. Out-of-step tripping.

1.3. Switch-on-to-fault.

1.4. Overcurrent relays.

1.5. Communications aided protection schemes including but not limited to:

1.5.1 Permissive overreach transfer trip (POTT).

1.5.2 Permissive under-reach transfer trip (PUTT).

1.5.3 Directional comparison blocking (DCB).

1.5.4 Directional comparison unblocking (DCUB).

1.6. Phase overcurrent supervisory elements (i.e., phase fault detectors) associated with current-based, communication-assisted schemes (i.e., pilot wire, phase comparison, and line current differential) where the scheme is capable of tripping for loss of communications.

2. The following protection systems are excluded from requirements of this standard:

2.1. Relay elements that are only enabled when other relays or associated systems fail. For example:

• Overcurrent elements that are only enabled during loss of potential conditions.

• Elements that are only enabled during a loss of communications except as noted in section 1.6

2.2. Protection systems intended for the detection of ground fault conditions.

2.3. Protection systems intended for protection during stable power swings.

2.4. Generator protection relays that are susceptible to load.

2.5. Relay elements used only for Special Protection Systems applied and approved in accordance with NERC Reliability Standards PRC-012 through PRC-017 or their successors.

2.6. Protection systems that are designed only to respond in time periods which allow 15 minutes or greater to respond to overload conditions.

2.7. Thermal emulation relays which are used in conjunction with dynamic Facility Ratings.

2.8. Relay elements associated with dc lines.

2.9. Relay elements associated with dc converter transformers.

Standard PRC-023-23 — Transmission Relay Loadability

PRC-023-3 — Attachment B Circuits to Evaluate

• Transmission lines operated at 100 kV to 200 kV and transformers with low voltage terminals connected at 100 kV to 200 kV.

• Transmission lines operated below 100 kV and transformers with low voltage terminals connected below 100 kV that are part of the BES.

Criteria

If any of the following criteria apply to a circuit, the applicable entity must comply with the standard for that circuit.

B1. The circuit is a monitored Facility of a permanent flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Québec Interconnection, that has been included to address reliability concerns for loading of that circuit, as confirmed by the applicable Planning Coordinator.

B2. The circuit is a monitored Facility of an IROL, where the IROL was determined in the planning horizon pursuant to FAC-010.

B3. The circuit forms a path (as agreed to by the Generator Operator and the transmission entity) to supply off-site power to a nuclear plant as established in the Nuclear Plant Interface Requirements (NPIRs) pursuant to NUC-001.

B4. The circuit is identified through the following sequence of power flow analyses5

a. Simulate double contingency combinations selected by engineering judgment, without manual system adjustments in between the two contingencies (reflects a situation where a System Operator may not have time between the two contingencies to make appropriate system adjustments).

performed by the Planning Coordinator for the one-to-five-year planning horizon:

b. For circuits operated between 100 kV and 200 kV evaluate the post-contingency loading, in consultation with the Facility owner, against a threshold based on the Facility Rating assigned for that circuit and used in the power flow case by the Planning Coordinator.

c. When more than one Facility Rating for that circuit is available in the power flow case, the threshold for selection will be based on the Facility Rating for the loading duration nearest four hours.

d. The threshold for selection of the circuit will vary based on the loading duration assumed in the development of the Facility Rating.

5 Past analyses may be used to support the assessment if no material changes to the system have occurred since the last assessment

Standard PRC-023-23 — Transmission Relay Loadability

i. If the Facility Rating is based on a loading duration of up to and including four hours, the circuit must comply with the standard if the loading exceeds 115% of the Facility Rating.

ii. If the Facility Rating is based on a loading duration greater than four and up to and including eight hours, the circuit must comply with the standard if the loading exceeds 120% of the Facility Rating.

iii. If the Facility Rating is based on a loading duration of greater than eight hours, the circuit must comply with the standard if the loading exceeds 130% of the Facility Rating.

e. Radially operated circuits serving only load are excluded.

B5. The circuit is selected by the Planning Coordinator based on technical studies or assessments, other than those specified in criteria B1 through B4, in consultation with the Facility owner.

B6. The circuit is mutually agreed upon for inclusion by the Planning Coordinator and the Facility owner.

Standards Authorization Request Form

Request to propose a new or a revision to a Reliability Standard

Title of Proposed Standard: NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric System definition (This is a supplement to the original SAR for this project which was approved by the Standards Committee on April 12, 2012.)

Date Submitted: January 16, 2013

SAR Requester Information

Name: Peter Heidrich

Organization: FRCC and Chair of the Definition of Bulk Electric System Standards Drafting Team

Telephone: 1.813.207.7994 E-mail: [email protected]

SAR Type (Check as many as applicable)

New Standard

X Revision to existing Standard

Withdrawal of existing Standard

Urgent Action

SAR Information

Industry Need (What is the industry problem this request is trying to solve?):

Address the directives in FERC Order 773 issued December 20, 2012.

Purpose or Goal (How does this request propose to address the problem described above?):

Address the directives in FERC Order 773 issued December 20, 2012.

Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables are required to achieve the goal?):

Address the directives in FERC Order 773 issued December 20, 2012.

Brief Description (Provide a paragraph that describes the scope of this standard action.)

Address the directives in FERC Order 773 issued December 20, 2012.

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Standards Authorization Request Form

Revised (11/28/2011) 2

SAR Information

Detailed Description (Provide a description of the proposed project with sufficient details for the standard drafting team to execute the SAR. Also provide a justification for the development or revision of the standard, including an assessment of the reliability and market interface impacts of implementing or not implementing the standard action.)

Address the directives in FERC Order 773 issued December 20, 2012.

Reliability Functions

The Standard will Apply to the Following Functions (Check each one that applies.)

This section is not applicable as the SAR is for a definition which is about Elements. Applicability of entities is covered in Section 4 of each Reliability Standard.

Regional Reliability Organization

Conducts the regional activities related to planning and operations, and coordinates activities of Responsible Entities to secure the reliability of the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator Responsible for the real-time operating reliability of its Reliability Coordinator Area in coordination with its neighboring Reliability Coordinator’s wide area view.

Balancing Authority Integrates resource plans ahead of time, and maintains load-interchange-resource balance within a Balancing Authority Area and supports Interconnection frequency in real time.

Interchange Authority Ensures communication of interchange transactions for reliability evaluation purposes and coordinates implementation of valid and balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner Develops a >one year plan for the resource adequacy of its specific loads within a Planning Coordinator area.

Transmission Planner Develops a >one year plan for the reliability of the interconnected Bulk Electric System within its portion of the Planning Coordinator area.

Transmission Service Administers the transmission tariff and provides transmission services

Standards Authorization Request Form

Revised (11/28/2011) 3

Reliability Functions

Provider under applicable transmission service agreements (e.g., the pro forma tariff).

Transmission Owner Owns and maintains transmission facilities.

Transmission Operator

Ensures the real-time operating reliability of the transmission assets within a Transmission Operator Area.

Distribution Provider Delivers electrical energy to the End-use customer.

Generator Owner Owns and maintains generation facilities.

Generator Operator Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling Entity

Purchases or sells energy, capacity, and necessary reliability-related services as required.

Market Operator Interface point for reliability functions with commercial functions.

Load-Serving Entity Secures energy and transmission service (and reliability-related services) to serve the End-use Customer.

Reliability and Market Interface Principles

Applicable Reliability Principles (Check all that apply).

X 1. Interconnected bulk power systems shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the NERC Standards.

X 2. The frequency and voltage of interconnected bulk power systems shall be controlled within defined limits through the balancing of real and reactive power supply and demand.

X 3. Information necessary for the planning and operation of interconnected bulk power systems

shall be made available to those entities responsible for planning and operating the systems reliably.

X 4. Plans for emergency operation and system restoration of interconnected bulk power systems shall be developed, coordinated, maintained and implemented.

X 5. Facilities for communication, monitoring and control shall be provided, used and maintained for the reliability of interconnected bulk power systems.

X 6. Personnel responsible for planning and operating interconnected bulk power systems shall be trained, qualified, and have the responsibility and authority to implement actions.

X 7. The security of the interconnected bulk power systems shall be assessed, monitored and maintained on a wide area basis.

Standards Authorization Request Form

Revised (11/28/2011) 4

Reliability and Market Interface Principles

X 8. Bulk power systems shall be protected from malicious physical or cyber attacks.

Does the proposed Standard comply with all of the following Market Interface Principles?

Enter

(yes/no)

1. A reliability standard shall not give any market participant an unfair competitive advantage.

Y

2. A reliability standard shall neither mandate nor prohibit any specific market structure.

Y

3. A reliability standard shall not preclude market solutions to achieving compliance with that standard.

Y

4. A reliability standard shall not require the public disclosure of commercially sensitive information. All market participants shall have equal opportunity to access commercially non-sensitive information that is required for compliance with reliability standards.

Y

Related Standards

Standard No. Explanation

N/A N/A

Related SARs

SAR ID Explanation

Project 2010-17: NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric System definition

This is the original SAR for the BES definition project – Phase 2. This SAR is a supplement to the original SAR.

Regional Variances

Region Explanation

ERCOT N/A

FRCC N/A

Standards Authorization Request Form

Revised (11/28/2011) 5

Regional Variances

MRO N/A

NPCC N/A

RFC N/A

SERC N/A

SPP N/A

WECC N/A

Functional Model Working Group (FMWG) of the North American Electric Reliability Corporation Date: November 26, 2012 Allen Mosher Chairman - Standards Committee Subject: Assessing the Need for Introducing Demand Response Functions and

Entities to the NERC Reliability Functional Model Dear Allen, Attached is a final report on the subject assessment, completed by the Functional Model Demand Response Advisory Team (FMDRAT) formed by the Standards Committee in July 2010. This assessment was conducted in response to a request by the Planning Committee at its December 8-9, 2009 meeting that the FMWG evaluate the need to include a Demand Response function and an associated functional entity either in the Functional Model or as an applicable entity for NERC Reliability Standards. The FMDRAT completed its initial assessment in the third quarter of 2011, and posted the report for public comment in the first quarter of 2012. The established process for standards development including responding to comments was applied to this posting, and revisions deemed appropriate to address industry comments were made to arrive at this final report. As such, we request the Standards Committee’s acceptance of this report, and its approval to post the report on the Related Files page of the FMWG Home Page as a reference document. If you or members of the Standards Committee have any questions on the report, please direct them to myself, Jerry Rust (FMWG vice-chair) or Ben Li (FMDRAT Chair). Thank you for the continuing support of the FMWG efforts. Sincerely,

Jim Jim Cyrulewski FMWG Chairman Cc: FMWG members Ben Li – Chair, FMDRAT

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FMDRAT Report November 8, 2012

A Report on

Assessing the Need for Introducing Demand Response Functions and Entities to the NERC

Reliability Functional Model Prepared by: Functional Model Demand Response Advisory Team

Executive Summary The Functional Model Demand Response Advisory Team (FMDRAT) has completed an assessment of the need to include Demand Response (DR) functions and associated functional entities either in the NERC Functional Model (FM) or as an applicable entity for NERC Reliability Standards.

The FMDRAT assessed a number of key issues related to the role and reliability impacts of DR in the planning and operation horizons. This assessment leads to the following key conclusions and recommendations:

1) DR is generally considered in Bulk Electric System (BES) planning and operations from the perspective of resource adequacy assessment and operating reserve determination. Long-term planners, operational planners and operators do take into account the amount of DR under contractual agreement or participated in operating reserve market to adjust resource needs to meet forecast system demand and reserve requirements. Since DR itself is not an active facility or component like a generator, its “dispatch” action is initiated upon receiving instructions from the operating authorities or via market mechanisms under pre-determined conditions. Compared to sudden load increase and generator tripping, DR’s spontaneous performance or failure to perform as instructed does not pose any new or unique Adverse Reliability Impacts on the BES for which there is no recourse. Hence, there is not a need at this time to include DR in the FM to describe its role in contributing to BES reliability.

2) Imposing reliability standards to force entities responsible for DR operations to comply with commercial agreements would be inappropriate, may not achieve the desired outcome, and in fact may discourage entities from participating in DR programs. There is thus no urgency or need to develop reliability standards to ensure compliance with what is essentially a business arrangement with commercial mechanisms already in place to drive the desired outcome.

3) The Functional Model Working Group (FMWG) should continue to monitor DR development and identify if and when DR technology and penetration levels create a unique impact on BES reliability.

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FMDRAT Report November 8, 2012

1.0 Introduction

The FMDRAT has completed an assessment of the need to include DR functions and associated functional entities either in the FM or as an applicable entity for NERC Reliability Standards. The issues considered by the FMDRAT and the key findings after discussing these issues are summarized in this report for consideration by the FMWG.

The FMDRAT is made up of 14 members appointed by the NERC Standards Committee. The FMDRAT’s roster is included as Attachment 1.

2.0 Background

In 2008, the FMWG set up a small advisory team to assess the need to create a DR function and a DR entity. That advisory team concluded that such a function and related functional entity were not justified at that time. The advisory team also suggested that the FMWG reconsider the issue when developing Functional Model Version 5 (FM V5). The advisory team recommended consideration of assigning such functions and responsibilities to functions and entities already defined in the FM.

The FMWG reconsidered the issue in its development of FM V5, and again concluded that there was no justification for defining a DR function and entity in the FM V5 Model. The NERC Planning Committee at its December 8-9, 2009 meeting, when approving the FM V5, requested the FMWG reassess the need to include a DR functional entity in FM V6. Below is the excerpt from the Planning Committee’s meeting minutes:

Functional Model Version 5: FMWG Chair Jim Cyrulewski presented an overview of the Functional Model, version 5. On a motion by John Simpson, the PC approved V5, without modification, the technical content of two documents: Reliability Functional Model, Function Definitions and Functional Entities and Reliability Functional Model Technical Document.

The primary discussion focused on what was not in version 5: a functional entity (or entities) responsible for demand resources. Mr. Cyrulewski noted that when the FMWG presents version 5 to the Standards Committee (SC) in January 2010 for approval, it will be recommending a new subgroup be formed to address the demand resources function so that it can be incorporated in version 6. John Simpson suggested that the PC’s Resource Issues Subcommittee be involved in that effort.

The Standards Committee, in response to the FMWG’s request, approved the formation of the FMDRAT to address the Planning Committee’s request. The FMDRAT was formed in May 2010, and from September 2010 to February 2011 completed its assignment to assess the need for a DR function and entity. This report presents the FMDRAT’s assessment and recommendations.

3.0 Key Issues Addressed by the FMDRAT

FMDRAT Report November 8, 2012

The FMDRAT began its tasks by identifying and compiling a list of potential reliability impacts associated with the participation of DR. The issues were important because the FM is a general description of the primary reliability tasks that need to be performed to ensure reliability of the BES.

The FMDRAT assessed the impact of DR from the following perspectives:

a. The unintended MW tripped or not tripped due to misoperation (mis-performance) of DR;

b. the hardware or facility that provides the mechanism for tripping loads that participate in a DR program; and

c. the aggregating of DR as a service, which is perceived to be purely a commercial/business arrangement.

Presented below is a summary of the FMDRAT’s assessment of each of the identified key issues.

3.1 Reliability Impact of DR - Does the change in energy use from a DR asset or from an aggregation of DR assets create any unique reliability impact?

DR is a temporary change in electricity usage by a demand resource in response to market or reliability conditions.1

Demand Response is regarded as a “dispatchable” resource (as opposed to energy efficiency, which is always “on”) whose deployment is driven by pre-determined system conditions or reliability event criteria by an operating entity. The system operator typically provides instruction to the DR provider for deployment of DR assets. Additionally, DR providers may self-schedule DR asset deployment, as in the case for economic dispatch in some regions.

A DR asset or aggregator that functions according to operating conditions as defined by prior agreements poses no impact to reliability because its impacts are analyzed and assessed in the operating plans of the respective Transmission Operator (TOP) and Balancing Authority (BA). The TOP and BA plan in advance to meet system load, including load that is represented or controlled by DR entities. TOPs and BAs have knowledge of all relevant conditions and agreements, and plan operations accordingly for the load to be served with or without contribution from DR. To the BA, load is a composite value (i.e., not locational) and a forecast can be developed for how much capacity is required to meet that load. Contractual arrangements with DR providers are accounted for in the BA’s operating plans. To the TOP, load is locational and it is based on historic load bus values. The DR control of load does not change the location of the basic load; rather, the availability of DR provides the TOP with another option to control congestion and to maintain reliability.

1 North American Energy Standards Board, Wholesale Electric Quadrant definition, 2010

FMDRAT Report November 8, 2012

From a MW change perspective, DR mis-performance does have some reliability impact on the BES but such impact is not expected to be at a level that will create Adverse Reliability Impact for which there is no remedy. This assessment is based on FMDRAT members’ experience with managing DR programs and accounting for DRs in operations and planning assessments, which indicates that the impacts from a failure of DR to respond on the power system are no different from a situation where a Generator Operator (GOP) does not generate to its cleared energy quantity or does not respond to requests to raise generation. At present, there are no reliability standards that mandate a GOP to comply with the business agreements. There are mechanisms in some areas (e.g., in some organized markets) to levy a penalty on the GOP for not meeting its commitment or requested output, but this is a commercial arrangement which falls outside of the scope of the FM or reliability standards. BAs and TOPs are similarly free to prescribe penalties for comparable failures of DR. Such penalty structures are not currently described in the FM, nor are there reliability standards developed to enforce compliance to such penalties. From a hardware/facility perspective, the unintended loss of DR is no different from losing a bus bar tripping all the loads connected to it, or from being inadvertently initiated by a common control scheme or device (other than the UFLS relay which can involve multiple bus bars). From an aggregation perspective, the FMDRAT assesses that this is purely a commercial or business service arrangement, which falls outside of the scope of planning or operating reliability. Observation 1: DR may be considered a dispatchable resource as compared to energy efficiency, which is always “on.” It is generally regarded as a load whose contractual arrangement is to be reduced in response to operating instructions or as triggered by market mechanisms, thus providing the intended reliability benefit and is well-known to system planners and operators. At present, there does not appear to be any Adverse Reliability Impact on the BES unique to DR resources where there is no recourse either for the DR’s reduction of load as planned, requested or tripping inadvertently, or the DR's failure to reduce load as planned or requested.

3.2 Reliance on DR to provide Operating Reserves

In some organized markets, DR may participate in the reserve market. In non-organized markets, DR may enter into contractual arrangements with the host utility to provide reserve capability. The FMDRAT assessed that the BA was responsible for ensuring adequate reserves in the operations time frame, required to understand the characteristics of the DR resources regardless of the market setup, and required to develop the necessary recourses to guard against DR’s failure to perform. Again, this situation is no different than generators not providing operating reserves. At present, there are no reliability standards that mandate a GOP to provide the needed reserves as procured or requested by the BA.

To manage the potential risk that DR fails to provide the dispatched or self-scheduled reserve quantity agreed upon, some organized markets apply a discount factor to the amount of reserves offered by a DR resource, while some organized markets limit DR participation to 30-minute reserve services. Still, others do not count on the DR to begin

FMDRAT Report November 8, 2012

with, but as load drops off, the responsible entity backs down the generation loaded in response to the activation in order to maintain adequate operating reserves.

Similar measures were determined by the FMDRAT to be adopted in non-organized markets through contractual arrangements.

Observation 2: BAs are responsible for managing the load and supply balance in their control areas. Dispatchable DR resources are generally considered in resource adequacy and operating reserve assessments in the operational planning time frame. However, it does not appear that DR presents any new or unique risks to the BES compared to any other dispatchable resource available to the TOP or BA. All responsible entities have measures in place to guard against the possibility that any dispatchable resource does not fulfill its obligations to provide the agreed amount of reserves. There are no unique Adverse Reliability Impacts on the BES for which there is no recourse when DR resources do not perform as planned or requested to provide the needed reserve.

3.3 DR resources’ obligations to support resource planning

Many planning entities consider DR in their mid-term and long-term resource planning processes. Some Planning entities consider DR as a resource to help meet the reserve margin requirement that is determined by either the traditional loss-of-load expectation (LOLE) process or by other commonly used methodologies.

Projected available DR may be applied as an available resource to help meet a reserve margin requirement, or applied as an offset to the long-term load forecast. Some planning entities apply a forced outage rate to the DR, similar to dispatchable generators, and simulate DR performance in LOLE calculations. In each case, some uncertainty exists around long-term DR resource availability due to the short-term contractual nature of DR assets as compared to the expected life of a generation asset. Some entities conduct more frequent resource adequacy assessments as the planning horizon approaches the near-term. An additional DR functional entity will not change the current role or responsibility of the planning coordinator or the resource planner.

Observation 3: Some entities consider DR in long-term planning and its treatment varies from one entity to another. However, owing to the long lead time in the planning process, there is uncertainty as to whether or not the status of the DR will remain unchanged as it approaches real time. An additional DR functional entity will not change the current role or responsibility of the planning coordinator or the resource planner.

3.4 Need for reliability standards to enforce compliance with contractual agreements/obligations

FMDRAT Report November 8, 2012

At present, DR is usually arranged via contractual agreements or market mechanisms such as pricing thresholds, reserve offerings, or forward capacity auctions. In these arrangements, penalties are levied if commercial or contractual obligations are not met. These mechanisms are similar to generators bidding into and being dispatched in an energy market and getting paid the market price or another pre-determined price based on the amount of generation provided. In such cases generators would not be paid (and in some cases assessed with additional penalties) if they failed to generate at the agreed upon or committed level. Given these contractual or commercial payment/penalty mechanisms, there do not appear to be gaps that would require the development and enforcement of reliability standards to achieve the desired DR performance. Imposing reliability standards to force compliance to commercial agreements is inappropriate, may not actually achieve the desired outcome, and may in fact discourage load from participating in DR programs.

The FMDRAT further assessed whether DR is a fundamental component or product of the BES. DR can provide some flexibility in both the long-term and operational planning time frames, to the extent that the responsible entities can choose which loads continue to be supplied. As such, DR may be considered a derivative product that should continue to be handled by commercial arrangements, not reliability standards.

Observation 4: Reliability standards are not required to enforce DR to comply with contractual agreements or obligations since DR participation is essentially a commercial arrangement. There are little or no material reliability impacts if DR fails to perform as agreed to or as requested (from Observations 1 and 2, above). Imposing reliability standards to force compliance to commercial agreements may not achieve the desired outcome of ensuring long-term reliability and may discourage entities from participating in DR programs.

3.5 DR Ownership and Operations – roles and relationships with others

In consideration of the possibility of introducing DR functions and entities to the FM, the FMDRAT developed a draft set of tasks describing a DR Ownership function and the relationship between the DR Owner and others. The FMDRAT also developed a draft set of tasks for a DR Operations function and the relationship between the DR Operator and others. The objective of this exercise was to compare the primary functions between the two types of resource providers. The FMDRAT concluded that a parallel to the tasks and relationships developed for the Generator Ownership and Generator Operations and their respective functional entities could be drawn for DR. The draft list of tasks and relationships for the DR Ownership and Operation functions and for the DR Owner and DR Operator is provided in Appendix A for information only. The FMDRAT did not finalize or accept the list provided in Appendix A in light of the FMDRAT’s assessment that introducing DR functions and associated entities to the FM is not required at this time. The list is provided herein only as a matter of record for future reference and is not part of the FMDRAT’s recommendation at this time.

FMDRAT Report November 8, 2012

3.6 Conclusion of Majority Position A near-unanimous consensus of the FMDRAT agreed with the analysis made for each of the key issues and the corresponding assessments detailed in this section of this report. The same majority agreed that that there is not a demonstrated need to introduce DR functions and entities to the FM at this time.

4.0 Minority Position

The key counter-arguments center on the comparable obligations between a DR Owner/Operator and Generator Owner/Operator (GO/GOP). At present, there are a number of reliability standards that apply to GOs and GOPs. DR providers may offer their product into energy or ancillary services markets and receive compensation for successful performance. They should bear the same obligations as their generation counterparts and hence should have a comparable set of reliability standards imposed on the DR Owners and DR Operators. However, if DR is not introduced to the FM and if DR were required to meet the same reliability standards, then a number of standards currently applied to GO and GOP, as listed in Appendix B, should be removed from the NERC Reliability Standards.

The FMDRAT assessed these minority views and arrived at the following assessments:

Apart from the fact that both generation and DR provide resources to the BES, there are some fundamental differences between them. Generators are a fundamental part of the integrated power system; they provide primary products for BES reliability – energy and ancillary services. Generators do change output in reaction to system changes and their changes are largely governed by their inherent physical characteristics and auxiliary device settings. These characteristics and settings need to be verified and modeled, and the simulated generator performance needs to be assessed against specific standards criteria to ensure that any adverse effects are self-contained or isolated without propagating to other parts of the BES which could result in uncontrolled or cascade tripping. It is largely on this basis, to ensure acceptable generator performance, that reliability standards are developed and imposed on GOs and GOPs.

DR is a derivative or supplementary part or product of the power system, with specific rules for participation in BES operations. DR augments the capabilities of the BES, thus increasing the effective utilization of the BES, but it does not expand the capability of the system to serve more loads, unlike its generator counterpart.

DR changes in load are inherently independent of system changes. Therefore, reliability standards are not needed to ensure acceptable performance as in the case of their generator counterpart. Commercial arrangements and compensation/penalty mechanisms are in place to govern DR contractual obligations and are sufficient to drive the desired behavior when DR is called upon to act. Imposing reliability standards to enforce such

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behavior is inappropriate and unnecessary and may not actually achieve the desired outcome.

As to the request to remove the listed reliability standards for the GOs and GOPs, the FMDRAT did not agree to a position since such a determination was not part of its charter.

5.0 Conclusions and Recommendations The FMDRAT assessed a number of key issues related to the role and reliability impacts of DR in the planning and operation horizons. The assessment leads to the following conclusions: 1. DR is generally considered in BES planning and operations from the perspective of resource

adequacy assessment and operating reserve determination. Recognizing the benefit that DR may provide, long-term planners, operational planners and operators do take into account the amount of DR under contractual agreement or participated in operating reserve market to adjust resource needs to meet forecast system demand and reserve requirements. Since DR itself is not an active facility or component like a generator, its “dispatch” action is initiated upon receiving instructions from the operating authorities or via market mechanisms under pre-determined conditions. Compared to sudden load increase and generator tripping, DR’s spontaneous performance or failure to perform as instructed does not pose any new or unique Adverse Reliability Impacts on the BES for which there is no recourse.

2. All responsible entities have some measures in place to guard against the possibility that a DR

resource does not fulfill its obligations to provide the agreed amount of reserves. 3. For long-term planning, most entities include contributions from DR to some extent.

Uncertainties associated with DR’s long-term commitment to remain “dispatchable” are typically addressed by applying a discount factor or probability analysis to DR’s availability in resource adequacy assessments.

4. In operational planning, there are no known entities that count on DR as a critical component of their operational plans. An additional DR functional entity will not change the current role or responsibility of the planning coordinator, resource planner, or operations planner.

5. Reliability standards are not required to enforce DR compliance with contractual agreements or

obligations. There are little or no reliability impacts caused by the failure of DR resources to perform as agreed to or as requested. Therefore, imposing reliability standards to force compliance with commercial agreements would be inappropriate, may not achieve the desired outcome, and in fact may discourage entities from participating in DR programs.

6. DR is a non-active component and a derivative product of the power system; it augments the

capabilities of the BES, thus increasing the effective utilization of the BES but it does not expand the system’s capability to serve more load and does not move spontaneously or in response to system changes for which reliability standards might be needed to ensure acceptable performance. Having commercial arrangements and compensation/penalty mechanisms in place to govern their contractual obligations would suffice to drive DR to achieve the desired behavior. Imposing reliability standards to enforce such behavior is extraneous and unnecessary.

FMDRAT Report November 8, 2012

Conclusions (1) to (4) suggest that there is no need at this time to include DR in the FM to describe its role in contributing to BES reliability. Conclusions (5) and (6) suggest that there is no urgency or need to develop reliability standards to ensure compliance with what is essentially a business arrangement with commercial mechanisms in place to drive the desired outcome.

It is on the above basis that the FMDRAT recommends:

1. DR functions and their associated functional entities not be defined and introduced to the FM at this time.

2. The FMWG continue to monitor DR development and identify if and when DR technology and penetration levels create a unique impact on BES reliability.

FMDRAT Report November 8, 2012

Attachment 1

The Functional Model Demand Response Advisory Team

Name Company

Ben Li (Chair/Facilitator) Ben Li Associates

1 Albert DiCaprio PJM

2 Phil Davis Schneider Electric

3 Stephen C. Knapp Constellation Energy Commodities Group, Inc.

4 John D. Varnell Tenaska Power Services Co

5 Donna Pratt NYISO

6 Ken Clark (did not participate) Consert, Inc.

7 Aaron Breidenbaugh EnerNOC

8 Wayne Van Liere LG&E and KU Energy LLC

9 Ulric Kwan Pacific Gas & Electric Company

10 Eric Winkler, Ph.D. ISO New England

11 Paul Wattles Electric Reliability Council of Texas (ERCOT ISO)

12 John Simpson RRI Energy

13 Andy Satchwell Lawrence Berkeley National Lab

14 Tony Jankowski We Energy

FMDRAT Report November 8, 2012

Appendix A DRAFT List of Perceived Tasks and Relationships for

Demand Response Functions and Entities (The list is provided for information and for future reference only; it is not part of the FMDRAT’s recommendation at this time.)

Generation Demand Response

Generator Ownership Function

Tasks

1. Establish generating facilities ratings, limits, and operating requirements.

2. Design and authorize maintenance of generation plant protective relaying systems, protective relaying systems on the transmission lines connecting the generation plant to the transmission system, and Special Protection Systems.

3. Maintains owned generating facilities.

4. Provide verified generating facility performance characteristics / data.

Functional Entity – Generator Owner

The functional entity that owns and maintains generating units.

Relationships with Others

1. Provides generator information to the Transmission Operator, Reliability Coordinator, Balancing Authority, Transmission Planner, and Resource Planner.

2. Provides unit maintenance schedules and unit retirement plans to the Transmission Operator, Balancing Authority, Transmission Planner, and Resource Planner.

Demand Response Ownership Function

Tasks

1. Establish demand response facility ratings, limits, and operating requirements.

2. Design and authorize maintenance of demand response facilities and associated control devices.

3. Maintains owned demand response facilities.

4. Provide verified demand response facility performance characteristics / data.

Functional Entity – Demand Response Owner

The functional entity that owns and maintains demand response facilities.

Relationships with Others

1. Provides demand response information to the Transmission Operator, Reliability Coordinator, Balancing Authority, Transmission Planner, and Resource Planner.

2. Provides demand response facility maintenance schedules to the Transmission Operator, Balancing Authority, Transmission Planner, and Resource Planner.

FMDRAT Report November 8, 2012

3. Develops an interconnection agreement with

Transmission Owner on a facility basis.

4. Receives approval or denial of transmission service request from Transmission Service Provider.

5. Provides reliability related services to Purchasing-Selling Entity pursuant to agreement.

6. Reports the annual maintenance plan to the Reliability Coordinator, Balancing Authority and Transmission Operator.

7. Revises the generation maintenance plans as requested by the Reliability Coordinator.

Function – Generator Operation

Tasks

1. Formulate daily generation plan.

2. Report operating and availability status of units and related equipment, such as automatic voltage regulators.

3. Operate generators to provide real and reactive power or reliability-related services per contracts or arrangements.

4. Monitor the status of generating facilities.

5. Support Interconnection frequency.

Functional Entity – Generator Operator

The functional entity that operates generating

3. Reports the annual maintenance plan to the Reliability Coordinator, Balancing Authority and Transmission Operator.

4. Revises the demand resource facility maintenance plans as requested by the Reliability Coordinator.

Function – Demand Response Operation

Tasks

1. Formulate daily demand response resource plan.

2. Report operating and availability status of demand response related equipment and control devices.

3. Operate demand response facility control devices or otherwise implement demand reduction or demand increase in response to instructions or according to contract arrangements.

4. Monitor the status of demand response facilities.

Functional Entity – Demand Resource Operator

The functional entity that operates demand

FMDRAT Report November 8, 2012

unit(s) and performs the functions of supplying energy and reliability related services.

Relationship with Others

Ahead of Time

1. Operate generators to provide real and reactive power or reliability-related services per contracts or arrangements.

2. Provides operating and availability status of generating units to Balancing Authority and Transmission Operators for reliability analysis.

3. Reports status of automatic voltage or frequency regulating equipment to Transmission Operators.

4. Provides operational data to Reliability Coordinator.

5. Receives reliability analyses from Reliability Coordinator.

6. Receives notice from Purchasing-Selling Entity if Arranged Interchange approved or denied.

7. Receives reliability alerts from Reliability Coordinator.

8. Receives notification of transmission system problems from Transmission Operators.

response facilities and performs the functions of curtailing or increasing demand in response to instructions or in accordance with contractual arrangement.

Relationship with Others

Ahead of Time

1. Implement demand reduction or consumption increase in response to instructions or according to contract arrangements.

2. Provides operating and availability status of demand response to Balancing Authority, Transmission Operator and Reliability Coordinator for reliability analysis.

3. Provides operational data to Reliability Coordinator.

4. Receives reliability analyses from Reliability Coordinator.

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Real Time

9. Provides Real-time operating information to the Transmission Operators and the required Balancing Authority.

10. Adjusts real and reactive power as directed by the Balancing Authority and Transmission Operators.

Real Time

5. Provides Real-time operating information to the Transmission Operators and the required Balancing Authority.

6. Adjusts demand in response to instructions or according to contract agreements.

Post Real Time

7. Provide operating information required Balancing Authority for settlement purposes

FMDRAT Report November 8, 2012

Appendix B

Minority Views

List of NERC Reliability Standards that should be removed if DR is not Assigned the Same Obligations as GO/GOP

On the basis of comparable treatment of “supply” resources used to balance load and supply in both the planning horizon and the real time operating horizon, a BA may choose between DR and traditional generation resources to meet the load obligations on the grid. As increased use is made of DR to meet certain load requirements, lower commitments are made of traditional generation supply. This is fine as long as the DR “supply” shows up when the BA calls on it.

Penalizing a DR that doesn’t perform as agreed to or as requested by penalizing it via market mechanisms is not acceptable from a reliability perspective. If sufficient DR doesn’t show up and traditional generation resources have not been committed and cannot get on-line in time to meet the aggregate demand, then some load will have to be curtailed against its desires in order to maintain BES reliability.

If it is indeed our position that whether or not DR responds when called upon that it does not impact reliability, then the following changes ought to be made to the existing reliability standards:

a) CIP Standards: remove GOPs from these standards. If it is not important for supply to respond when called on then we don’t need these standards applied to any supply resources.

b) COM-002: remove GOPs from this standard. If DR that is used as a supply resource doesn’t need to respond, then GOPs do not need to have communications with the Reliability Coordinators (RCs) for them to respond either.

c) IRO-001,-004,-005,-010: remove GOs and GOPs from these standards. If it is not important that DR used as a supply resource responds to the directives of the RC, then it should not be important that GO/GOPs respond either. They also should not have to provide information on their capabilities in Day Ahead or Current Day time frames. There also shouldn’t be a need to coordinate any maintenance outages with the RC. After all, if a DR owner or operator can just sit out for a day, then a generator should be able to do the same thing.

d) MOD-024,-025: delete these standards. If it is not important to know or qualify the capacity of a DR resource, then we should not have to qualify the capacity of a traditional generation resource either.

e) PRC-001,-005: remove GOP and GO from these standards. If it is not important to reliability that DR operates properly when called on, then we should not have to coordinate protective relays or do protection system maintenance for traditional generation resources either.

f) TOP-001,-002,-003,-006: remove GOPs from these standards. If it is not important that DR, which is being counted on by the BA, responds to directives from the RC, then we shouldn’t need to have GOPs respond either. There shouldn’t be a need to coordinate normal operations planning with the RC, coordinate outage schedules with the RC, or provide notice to the RC of any resources that are available or not available for dispatch.

FMDRAT Report November 8, 2012

As more and more DR is included in the dispatch stack and the planning and operating horizon, fewer real generation resources are included to meet the aggregate load obligations on the grid. It is certainly important to the BA and the RC that the real generation resources can be counted on to perform when called. As DR replaces those real generation resources, it should be important that they respond as well. Comparable reliability standard requirements should be in place for DR resources as are in place for GOs and GOPs.

Item 7b-1

WICF GOTO White Paper on Interconnection Facility

In July 2012, as part of Project 2010-07: Generator Requirements at the Transmission Interface, NERC filed revisions to FAC-001, FAC-003, PRC-004, and PRC-005 to address the inclusion of generator interconnection Facilities where, without that specific inclusion, there could have been a reliability gap with regard to responsibility for those interconnection Facilities. FERC has not yet responded to this filing.

Since that filing, members of the Western Interconnection Compliance Forum (WICF) have expressed their support for the work of the 2010-07 drafting team and the revisions proposed in the filing. WICF members also suggested that a recommendation or guideline be put in place for ensuring that generator interconnection Facilities be given appropriate consideration – in the same manner that the 2010-07 drafting team considered them – in future work. After some discussion with NERC staff about the best way to ensure drafting team consideration of generator interconnection Facilities in new and revised Reliability Standards, the Western Interconnection Compliance Forum (WICF) submitted the attached white paper asking the Standards Committee to consider possible solutions for addressing WICF’s concern.

NERC staff asks that the Standards Committee appoint a small team to work with NERC staff to propose a solution to WICF’s concern by January 31, 2013.

December 10, 2012 WICF Generator Lead Line White Paper: Forward Look at Project 2010-07

Impact on the Standard Development Process Background The Western Interconnection Compliance Forum (WICF) has been engaged by NERC to provide comments on key reliability matters. As a mechanism to formulate such technical discussion, WICF has formed various focus groups to vet these matters among registered entities. The WICF GOTO focus group was formed to stay abreast of the Generator Lead Line issue. This group’s charter has two primary goals:

1) Develop collaborative compliance approaches to all current and future GOTO related standards filed with FERC for approval.

2) Work with NERC, FERC, NAGF, and others to establish a reasonable path forward for additional issues related to Generator Lead Line regulatory compliance.

Both NERC and WECC participate in the current GOTO focus group (as requested), with Jack Wiseman acting as the NERC liaison. Mallory Huggins has also been involved in the formation of this white paper. WICF would like to take this opportunity to thank our NERC liaisons and NERC as an organization for their original request for assistance from WICF. Discussion The WICF GOTO focus group applauds the industry and NERC for the July 2012 filing with FERC to request approval of Project 2010-07—Generator Requirements at the Transmission Interface. The WICF GOTO group feels strongly that the perceived reliability gap has been addressed by this Project. However, we want to look forward to ensure the great work done by this drafting team carries on to new and revised standards as they are developed. Essentially, the Project can be summarized in that the term “Interconnection Facilities” was added to applicable standards to ensure that the scope of the standard included the Generator Lead Line/Interconnection Facility. It is appropriate that the concepts developed by Project 2010-07 concerning interconnection facilities (aka lead lines) associated with generation are preserved in all new and revised standards as they are developed in the future. This is especially important now as some standard drafting teams (SDTs) may be revising or creating new standards that should maintain the language proposed for revision by Project 2010-07, which is still in final approval process. There is no mechanism to address inclusion of the term “Interconnection Facilities” in future standard development or revisions.

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While Project 2010-07 solves the current perceived reliability gap, the WICF GOTO group thinks it is important to alert the SDTs of the lead line implications so their fantastic work forming new standards will not become obsolete. For example, the SDTs decided PRC-005-1 needed to be revised to address lead lines, butthe revisions were made for the FERC submission were not carried over to the recent industry approval of PRC-005-2. Therefore, the work done by the drafting team will be obsolete, creating a new potential reliability gap if Revision 2 of this standard is implemented as currently written. The notification being suggested by the WICF GOTO focus group does not need to be high-profile, which may to hinder the approval of the Project 2010-07 by FERC. However, this issue does need to be addressed. Therefore, the WICF GOTO focus group recommends updating the processes/procedures for both NERC and the Regional Entities to include a control to ensure that Interconnection Facilities are considered for every project. The justification for inclusion or exclusion must be documented. Obviously, some standards/projects will have no impact on generation lead leads, so the justification will simply reflect that in writing. However, for the standards that involve generation lead lines, the registered entities (both transmission and generation) deserve to know the compliance expectation associated with the standard as it relates to Interconnection Facilities. If it is determined and documented that Interconnection Facilities need not be addressed, that documentation can be archived in the project files. However, in the instances where Interconnection Facilities are implicated in compliance monitoring activities, the wording of applicable standard requirements will be similar to the adjustments made for the four GOTO standards sent to FERC for approval in August. This effort is applicable to TOs and TOPs as much as it is GOs and GOPs, as transmission entities have indicated that they do not want interference in operation of the transmission grid from generation organizations that are not equipped for operation of these facilities. Conversely, the generation entities are currently not able to comply with many standards, as evidenced by the work of the GOTO drafting team. The WICF GOTO focus group believes standards that apply to regional entities, transmission planners, Transmission Owners and Operators, and especially to Generator Owners and Operators, should be included. This will ensure that generator-owned interconnection facilities interconnected to the bulk power system shall be planned and operated in a coordinated manner to perform reliably under normal and abnormal conditions as defined in the applicable NERC Standards. Request

The WICF GOTO Focus Group respectfully requests that the NERC Standards Committee consider this whitepaper to achieve the goal of updating NERC and Regional Entity processes to ensure that all SDTs are required to consider Interconnection Facilities in development of all new applicable standards. We would appreciate a response to the white paper by January 31, 2013.

January 2013

1

NERC Legal and Regulatory Filings - Standards

RECENT FILINGS

DATE PROJECT/DESCRIPTION November 29, 2012 Quarterly filing regarding timeframe to restore power to the auxiliary

power systems of U.S. Nuclear Power Plants following a blackout as determined during simulations and drills of system restoration plans; Docket No. RM06-16-000

December 11, 2012 Reply Comments on NOPR on Reliability Standard PRC-006-NPCC-1 – Automatic Underfrequency Load Shedding, Docket No. RM12-12-000

December 21, 2012 Comments on NOPR on FAC-003-2, Docket No. RM12-4-000 December 26, 2012 Comments on NOPR on GMD, Docket No. RM12-22-000 December 31, 2012 Petition for Approval of Project 2009-01

Disturbance and Sabotage Reporting – EOP-004-2 December 31, 2012 Reliability Standards Development Plan

UPCOMING FILING DATES

DATE PROJECT/DESCRIPTION January 31, 2013 DUE DATE: BAL-003 quarterly report January 31, 2013 DUE DATE: Ballot results quarterly report

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Item 8b

January 2013

2

PROJECTED FILINGS

STATUS PROJECT/DESCRIPTION Status: BOT Approved Projected Filing Date: January 31, 2013

Project 2008-06-Cyber Security, CIP Version 5

Status: BOT Approved Projected Filing Date: January 31, 2013

WECC Regional Variance: VAR-001-3 -Voltage and Reactive Control

Status: BOT Approved Projected Filing Date: January 31, 2013

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

Status: BOT Approved Projected Filing Date: January 31, 2013

2007-17 Protection System Maintenance Testing (PRC-005-2)

Status: BOT Approved Projected Filing Date: TBD

COM Standards: (2006-06 - Reliability Coordination – COM-001-2 and COM-002-3 / Project 2009-22 - Interpretation of COM-002-2)

Status: BOT Approved Projected Filing Date: TBD

Regional Reliability Standard PRC-006-SPP-01

Status: BOT Approved Projected Filing Date: TBD

Interpretation 2010-INT-01 ― Rapid Revision of TOP-006-2 in Response to FMPP’s Request for Interpretation

3353 Peachtree Road NE Suite 600, North Tower

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

December 20, 2012  Tom Bowe, Chair, NERC Operating Committee Jeff Mitchell, Chair, NERC Planning Committee Allen Mosher, Chair, NERC Standards Committee  RE: Reliability Issues Nomination Form Concerning Geomagnetic Disturbances (GMD)  Dear Tom, Jeff, and Allen,  At its December 17 meeting, the RISC discussed the attached Reliability Issues Nomination Form concerning GMD.  After consideration and discussion concerning the issue, the RISC concluded that important work of the Geomagnetic Disturbance Task Force (GMDTF), currently formed jointly under the NERC Operating and Planning Committees, on the issue should be completed before the next steps are taken to ensure that any future NERC action‐‐including any NERC Reliability Standard‐‐reflects best practices and a consensus approach on the technical issues.  As a result, the RISC requests:  

the GMDTF review its schedule and deliverables in light of the standards proposed in the GMD NOPR and present its work plan to the RISC at its January 24, 2013 meeting regarding whether the GMDTF schedule can be expedited and whether the GMDTF deliverables will provide a solid technical basis on which to evaluate next steps; 

  the Operating Committee leverage its relationships with transmission operators to undertake a 

review of best operating practices that prepare for and respond to a GMD event and report to the RISC at its January 24, 2013 meeting concerning if these best practices could be shared across the industry and how and when to best accomplish that objective;  

  the Standards Committee not initiate formal processing of any Standard Authorization Request 

relating to GMD until the work detailed above is complete or until FERC directs specific action.  Please feel free to call me if you have any questions or concerns regarding these requests.  We will plan to add you to our January 24, 2013 teleconference meeting agenda.    

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Item 9a

Thank you and my best wishes for a happy holiday season to you.  Sincerely, 

Chris Schwab  Chris Schwab Chair, Reliability Issues Steering Committee  cc:  Mr. Kenneth Donohoo, Chair, NERC Geomagnetic Disturbance Task Force    Mr. Jim Castle, Vice Chair, NERC Operating Committee    Mr. Ben Crisp, Vice Chair, NERC Planning Committee    Mr. Ben Li, Vice Chair, NERC Standards Committee    Mr. Larry Kezele, NERC Staff Coordinator, NERC Operating Committee    Mr. Dave Nevius, NERC Staff Coordinator, NERC Planning Committee   Ms. Kristin Iwanechko, NERC Staff Coordinator, NERC Standards Committee   Mr. Andy Rodriquez, NERC Staff Coordinator, Reliability Issues Steering Committee    NERC Reliability Issues Steering Committee Members    

S - Vacancy Report

Project Vacancy Description

Project 2007-06 System Protection Coordination Seeking an individual from a Canadian entity with experience in coordination of Protection Systems (new installationsand revisions).

S - Vacancy Report Page 1 1/9/13 12:06 PM

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Item 9b

Standards Committee 2013 Segment Representatives

* New to Standards Committee

Chairman Allen Mosher was elected as SC chairman for a two year term, ending on Dec. 31, 2013. Ben Li was elected as SC vice chairman for the same term. However, Allen has announced that he will step down as chair at the January 2013 meeting.

A nominating committee has been formed and an election for SC chair and vice chair will be conducted at the January 2013 SC meeting.

Vice-chairman

Segment and Term Representative Organization

Segment 1-2013-14 Lou Oberski*

Managing Director, NERC Compliance Policy

Dominion Resources Services, Inc.

Segment 1-2012-13 Carol A. Sedewitz Director, Transmission Planning

National Grid

Segment 2-2013-14 Al DiCaprio

Senior Strategist

PJM Interconnection, LLC

Segment 2-2012-13 H. Steven Myers

Principal, Operating & Planning Standards

ERCOT

Segment 3-2013-14 Jennifer Sterling*

Director, Exelon NERC Compliance Program

Exelon

Segment 3-2012-13 John Bussman

Manager Reliability Compliance

Associated Electric Cooperative Inc.

Segment 4-2013-14 Joseph Tarantino

Regulatory Compliance Coordinator

Sacramento Municipal Utility District

Segment 4-2012-13 Frank Gaffney

Assistant General Manager of and Officer of Regulatory Compliance

Florida Municipal Power Authority

Segment 5-2013-14 Gary Kruempel

Compliance Director, Energy Supply

MidAmerican Energy Company

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Item 9c

Standards Committee 2013 Roster 2

Segment and Term Representative Organization

Segment 5-2012-13 Scott Miller

Manager, Corporate Affairs

MEAG Power

Segment 6-2013-14 Brian Murphy*

Manager, NERC Reliability Standards Compliance

NextEra Energy, Inc.

Segment 6-2012-13 Alice Murdock Ireland

Reliability Standard Analyst

Xcel Energy, Inc.

Segment 7-2013-14 John A. Anderson

President & CEO

Electricity Consumers Resource Council

Segment 7-2012-13 Frank McElvain

Senior Consulting Manager

Siemens Energy, Inc.

Segment 8-2013-14 Vacant – no nominees

Segment 8-2012-13 Frederick Plett

Utility Analyst

Massachusetts Attorney General

Segment 9-2013-14 Diane J. Barney

Utility Supervisor

New York State Public Service Commission

Segment 9-2012-13 Klaus Lambeck

Chief Facilities, Siting and Environmental Analysis

Public Utilities Commission of Ohio/the Ohio Power Siting Board

Segment 10-2013-14 Pending outcome of Segment 10 Election

Segment 10-2012-13 Linda Campbell

Vice President and Executive Director, Standards and Compliance

Florida Reliability Coordinating Council

Canada 2013 David Kiguel

Manager, Reliability Standards

Hydro One Networks Inc.

Parliamentary Procedures Based on Robert’s Rules of Order, Newly Revised, 10th Edition, plus “Organization and Procedures Manual for the NERC Standing Committees”

Motions Unless noted otherwise, all procedures require a “second” to enable discussion.

When you want to… Procedure Debatable Comments Raise an issue for discussion

Move Yes The main action that begins a debate.

Revise a Motion currently under discussion

Amend Yes Takes precedence over discussion of main motion. Motions to amend an amendment are allowed, but not any further. The amendment must be germane to the main motion, and can not reverse the intent of the main motion.

Reconsider a Motion already approved

Reconsider Yes Allowed only by member who voted on the prevailing side of the original motion.

End debate Call for the Question or End Debate

Yes If the Chair senses that the committee is ready to vote, he may say “if there are no objections, we will now vote on the Motion.” Otherwise, this motion is debatable and subject to 2/3 majority approval.

Record each member’s vote on a Motion

Request a Roll Call Vote

No Takes precedence over main motion. No debate allowed, but the members must approve by 2/3 majority.

Postpone discussion until later in the meeting

Lay on the Table Yes Takes precedence over main motion. Used only to postpone discussion until later in the meeting.

Postpone discussion until a future date

Postpone until Yes Takes precedence over main motion. Debatable only regarding the date (and time) at which to bring the Motion back for further discussion.

Remove the motion for any further consideration

Postpone indefinitely

Yes Takes precedence over main motion. Debate can extend to the discussion of the main motion. If approved, it effectively “kills” the motion. Useful for disposing of a badly chosen motion that can not be adopted or rejected without undesirable consequences.

Request a review of procedure

Point of order No Second not required. The Chair or secretary shall review the parliamentary procedure used during the discussion of the Motion.

Notes on Motions Seconds. A Motion must have a second to ensure that at least two members wish to discuss the issue. The “seconder” is not recorded in the minutes. Neither are motions that do not receive a second.

Announcement by the Chair. The Chair should announce the Motion before debate begins. This ensures that the wording is understood by the membership. Once the Motion is announced and seconded, the Committee “owns” the motion, and must deal with it according to parliamentary procedure.

Attachment 1d

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Voting Voting Method When Used How Recorded in Minutes Unanimous Consent When the Chair senses that the Committee

is substantially in agreement, and the Motion needed little or no debate. No actual vote is taken.

The minutes show “by unanimous consent.”

Vote by Voice The standard practice. The minutes show Approved or Not Approved (or Failed).

Vote by Show of Hands (tally) To record the number of votes on each side when an issue has engendered substantial debate or appears to be divisive. Also used when a Voice Vote is inconclusive. (The Chair should ask for a Vote by Show of Hands when requested by a member).

The minutes show both vote totals, and then Approved or Not Approved (or Failed).

Vote by Roll Call To record each member’s vote. Each member is called upon by the Secretary,, and the member indicates either “Yes,” “No,” or “Present” if abstaining.

The minutes will include the list of members, how each voted or abstained, and the vote totals. Those members for which a “Yes,” “No,” or “Present” is not shown are considered absent for the vote.

Notes on Voting (Recommendations from DMB, not necessarily Mr. Robert)

Abstentions. When a member abstains, he is not voting on the Motion, and his abstention is not counted in determining the results of the vote. The Chair should not ask for a tally of those who abstained.

Determining the results. The results of the vote (other than Unanimous Consent) are determined by dividing the votes in favor by the total votes cast. Abstentions are not counted in the vote and shall not be assumed to be on either side.

“Unanimous Approval.” Can only be determined by a Roll Call vote because the other methods do not determine whether every member attending the meeting was actually present when the vote was taken, or whether there were abstentions.

Majorities. Robert’s Rules use a simple majority (one more than half) as the default for most motions. NERC uses 2/3 majority for all motions.

Standards Committee Meeting Dates and Locations for 2013

Conference calls are held each month where the SC does not have a face-to-face meeting. These calls are on one Thursday each month from 1-5 pm Eastern. Face-to-face meetings are conducted from 8-5 pm on the first day and 8-3 pm the second day. The time for face-to-face meetings is based on the ‘local’ time zone. The time specified for all conference calls is based on the Eastern time zone. In order to schedule the face-to-face meetings so they align with the standing committee meetings and occur two months prior to each NERC Board of Trustees meeting, the January face-to-face will occur as scheduled with the next face-to-face in March. This realignment will also call for a fifth face-to-face meeting in December. Further, because there is a face-to-face meeting in the middle of January and another in the beginning of March, there will not be a conference call held in February.

• January 16-17, 2013 – Atlanta (8-5 pm January 16; 8-3 pm January 17) • February 2013 – no conference call • March 7-8, 2013 – Albuquerque (8-5 pm March 7; 8-3 pm March 8) • April 4, 2013 conference call from 1-5 pm • May 2, 2013 conference call from 1-5 pm • June 5-6, 2013 – Atlanta (8-5 pm June 5; 8-3 pm June 6) • July 18, 2013 conference call from 1-5 pm • August 22, 2013 conference call from 1-5 pm • September 19-20, 2013 – Denver (8-5 pm September 19; 8-3 pm September 20) • October 17, 2013 conference call from 1-5 pm • November 14, 2013 conference call from 1-5 pm • December 12-13, 2013 – Atlanta (8-5 pm December 12; 8-3 pm December 13)

The Standards Committee has two subcommittees (Communications and Planning Subcommittee and Process Subcommittee) and these typically meet for either a whole day or a half day on the day immediately preceding the Standards Committee’s face-to-face meetings. Thus, expect a meeting of the subcommittees on the following dates:

• January 15, 2013 in Atlanta • March 6, 2013 in Albuquerque • June 4, 2013 in Atlanta

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Item 9e

Standards Committee Meeting Dates and Locations for 2013 2

• September 18, 2013 in Denver • December 11, 2013 in Atlanta