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Agenda Standards Committee

Wednesday, December 8, 2010 | 1–4 p.m. Eastern Dial-in Number: 866-740-1260 Participant Code: 4685998

1. Administrative Items

a. Introductions and Quorum — A. Mosher (Attachment 1a)

b. Conference Call Reminder

c. NERC Antitrust Compliance Guidelines — M. Long (Attachment 1b)

d. Meeting Agenda [Approve] — A. Mosher

e. Waiver of 5-day rule [Approve] — A. Mosher 2. Consent Agenda (Approve)

a. November 11, 2010 Standards Committee Meeting Minutes [Approve] (Attachment 2a)

b. November 24, 2010 Executive Committee Meeting Minutes [Ratify] (Attachment 2b)

c. Project 2009-02 - Real-time Reliability Monitoring and Analysis Capabilities Standard Drafting Team – Appoint a member to the team [Appoint] (Attachment 2c-Confidential)

3. Status of High Priority Projects, Activities and Action Items

a. Status of high priority projects — D. Taylor (Attachment 3a)

b. Status of high priority activities and open action items — A. Mosher (Attachment 3b)

4. Standards Actions

a. Project 2007-07 - Vegetation Management – Authorize posting for a comment period with a parallel successive ballot (Attachment 4ai, 4aii)

b. Project 2010-07 - Transmission Requirements at the Generator Interface – Accept the SAR as final; appoint the team to serve as the Standard Drafting Team; authorize the team to proceed as proposed with standard development (Attachment 4bi, 4bii)

Standards Committee Draft Meeting Agenda December 8, 2010

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c. SAR for revision to definition of Bulk Electric System – authorize posting the SAR; appoint the SAR authors to the drafting team; direct staff to solicit additional nominees (Attachment 4c - to be sent separately)

d. Project 2010-10 – FAC Order 720 – Authorize posting for a comment period with a parallel successive ballot (Attachment 4d - to be sent separately)

e. Project Prioritization – Approve Tool; Identify High Priority Projects; Identify Work to Defer — D. Taylor (Attachment 4e - to be sent separately)

f. Authorize Posting for a Comment Period with a Parallel Successive Ballot

5. Coordination

a. Coordination with Regulatory and Governmental Authorities — Holly Hawkins

b. Coordination with Regional Managers — T. Gallagher and H. Schrayshuen

6. Other Items

a. Update on Annual SC Elections

b. Interconnection-wide Variance to CIP-001

7. Informational Items

a. Status of all Interpretations (Attachment 7a)

b. Drafting Team Vacancies (Attachment 7b)

c. Upcoming Project Meetings (Attachment 7c)

8. Executive Committee Actions — M. Long

Items expected to come before the Standards Committee’s Executive Committee before January 11, 2011 [Pre-authorize]

Project 2006-06 – Reliability Coordination – Authorize posting for parallel comment and ballot

Project 2010-10 – FAC Order 720 – Authorize use of the expedited process to meet the January 28 FERC filing date

Project 2010-13 – Relay Loadability Order 733 – Phase II Standard Drafting Team – Appoint a member to the team

9. Adjourn


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1. Administrative Items

Introductions —Standards Committee Chair Allen Mosher will lead the introduction of committee members and determine if there is a quorum.

Conference Call Reminder - Participants are reminded that the conference call meeting is public and open to all interested parties. 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.

NERC Antitrust Compliance Guidelines — Maureen Long will review the NERC Antitrust Compliance Guidelines provided in Attachment 1b. 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.

Meeting Agenda — Allen Mosher will review the meeting agenda and ask for modifications before the agenda is approved.

Waiver of 5-day rule — If there are items submitted to the Standards Committee for action with less than 5 days notice, those items cannot be added to the agenda without the unanimous consent of the members present. If any items fall into this category Allen Mosher will ask the Standards Committee to vote on waiving the 5-day rule.

2. Consent Agenda

a. Approve the Consent Agenda The consent agenda allows the Standards Committee to approve routine items that would normally not need discussion. Any Standards Committee member may ask the chair to remove an item from the consent agenda for formal discussion.

The chair will ask the committee to approve, ratify, acknowledge, or appoint as appropriate the following from the consent agenda:

a) November 11, 2010 Standards Committee Meeting Minutes

b) November 24, 2010 Executive Committee Meeting Minutes

c) Project 2009-02 - Real-time Reliability Monitoring and Analysis Capabilities Standard Drafting Team – Appoint a member to the team

3. Status of High Priority Projects, Activities and Action Items a. Status of High Priority Projects


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David Taylor will review the status of high priority projects, with a focus on those projects that are experiencing issues causing project delays.

Status of High Priority Activities and Open Action Items Allen Mosher will review the list of high priority activities selected for Standards Committee attention in 2010, and the status of open action items.

4. Standards Actions — M. Long

a. Project 2007-07 - Vegetation Management – Authorize Posting for a Comment Period with a Parallel Successive Ballot

Background: An initial ballot of FAC-003 – Transmission Vegetation Management was conducted from July 9-19, 2010. The ballot achieved a quorum and an overall weighted segment approval of 65.93%. The team has been working since then to address stakeholder comments and comments from NERC and FERC staffs.

The team submitted a revised set of documents and they underwent a quality review on November 4, 2010. The review was provided to the drafting team and to the Standards Committee and the Standards Committee directed the team to work with NERC staff in making revisions to the standard. The team has made a good faith effort to comply with the Standards Committee’s direction and has made many changes to the standard in support of the observations from the Quality Review.

Request: Authorize posting FAC-003-2 for a comment period with a parallel successive ballot.

b. Project 2010-07 - Transmission Requirements at the Generator Interface – Accept the SAR as Final; Appoint the Team to Serve as the Standard Drafting Team; Authorize the Team to Move Forward as Proposed with Standard Development

Background: The GOTO Team has completed its work in refining its SAR and has developed an action plan for developing the definitions and requirements. The team has proposed a schedule that would bring the requirements and definitions into effect at the same time to eliminate any gaps in reliability that could result from phased implementation where some requirements become effective before others.

Request: Accept the SAR as final; appoint the members of the GOTO SAR DT to serve as the Standard Drafting Team and authorize the team to move forward as proposed.

c. SAR for Revision to Definition of Bulk Electric System – Authorize Posting the SAR; Appoint the SAR Authors to the Drafting Team; Direct Staff to Solicit Additional Nominees

Background: Order 743, issued on November 18, 2010 directed NERC to revise the definition of Bulk Electric System within 12 months of the effective date of the Order (60 days after publication in the Federal Register). Key items from the Order: ensure the definition encompasses all facilities necessary for operating an

interconnected electric transmission network eliminate the regional discretion in the current definition


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maintain a bright-line threshold that includes all facilities operated at or above 100 kV except defined radial facilities

establish an exemption process and criteria for excluding facilities that are not necessary for operating the interconnected transmission network

An ad hoc group representing several NERC Regions was already working on a SAR to propose a revision to the definition of Bulk Electric System when the November 18, 2010 BES Order was issued. The team revised its SAR to reflect consideration of the Order. As envisioned, the exception process will be added to the ERO Rules of Procedure. Developing the exception process will take place outside the standard development process. The drafting team will need to coordinate with those working on the exception process. Both must be filed in January 2012. Request: Authorize posting the SAR and proposed revisions for the definition of Bulk Electric System; appoint the authors of the SAR to the drafting team, and direct staff to solicit additional nominations to provide the team with sufficient technical diversity.

d. Project 2010-10 – FAC Order 720 – Authorize Posting for a Comment Period with a Parallel Successive Ballot

The FAC Order 729 SDT submitted its responses to the comments it received during a comment period, an initial ballot, and a non-binding poll that ended on November 3, 2010. The team made conforming changes to the standard and the revised standard has been submitted to a team for a Quality Review. The results of the Quality Review will be forwarded to the Standards Committee as soon as they are available.

e. Project Prioritization – Approve Tool; Identify High Priority Projects; Identify Work to Defer

A project prioritization tool has been developed that assigns weights to various criteria associated with a project. The tool was designed for use by all involved in determining project priorities with a goal of having a reasonable set of project that key players agree upon. The tool was developed and field tested with existing and planned projects.

David Taylor will present the tool and the project prioritization produced by applying the tool to the projects that had been under development as of November 30, 2010.

The Standards Committee will be asked to:

Approve use of the tool

Identify 8-12 of the highest priority projects for active development

Direct the deferral of work on remaining projects until resources allocated to the high priority projects become available


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The list of high priority projects is expected to change as some projects are completed and others are added to meet changing conditions.

5. Coordination

a. Coordination with Regulatory and Governmental Authorities — H. Hawkins

Holly Hawkins will provide highlights of the following Notices of Proposed Ruling and Orders issued by FERC on November 18, 2010:

Order 743: Revision to Electric Reliability Organization Definition of Bulk Electric System Order 742: System Personnel Training Reliability Standards Final Rule Notice of Proposed Ruling: System Restoration Reliability Standards Notice of Proposed Rulemaking Notice of Proposed Ruling: Mandatory Reliability Standards for Interconnection Reliability Operating Limits Notice of Proposed Rulemaking Notice of Proposed Ruling: Integration of Variable Energy Resources Notice of Proposed Rulemaking

Holly will also provide an update on progress in filing standards and standards-related documents with FERC and Canadian governmental authorities.

b. Coordination with Regional Managers — T. Gallagher and H. Schrayshuen

Tim Gallagher and Herb Schrayshuen will provide an update on standards-related activities involving the Regions.

6. Other Items

a. Update on Annual SC Elections

Maureen Long will provide an update on the status of Standards Committee elections for the 2-year term 2011-2013.

a. Interconnection-wide Variance added to CIP-001-1a - Sabotage Reporting

ERCOT developed an Interconnection-wide variance to CIP-001-1a using its NERC-approved standard development process. The variance expands the applicability beyond the applicability in the continent-wide requirements (Reliability Coordinators, Balancing Authorities, Transmission Operators, Generator Operators, and Load Serving Entities) to include Transmission Owners and Generator Owners. No changes were made to the language of the requirements, measures, or other elements of the standard beyond expansion of the applicability. The continent-wide standard is currently being revised under Project 2009-01 – Disturbance and Sabotage Reporting, and the proposed revisions do include expansion of applicability to include the Transmission Owner and Generator Owner.

7. Informational Items


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b. Status of all Interpretations

c. Drafting Team Vacancies

d. Upcoming Meetings for High Priority Projects

8. Executive Committee Actions — M. Long

a. Items Expected to Come Before the Standards Committee’s Executive Committee Before January 12, 2011

i) Project 2006-06 – Reliability Coordination – Authorize posting for parallel comment and ballot

ii) Project 2010-10 – FAC Order 720 – Authorize use of the expedited process to meet the January 28 FERC filing date

iii) Project 2010-13 – Relay Loadability Order 733 – Phase II Standard Drafting Team – Appoint additional members to the team; appoint a chair and vice chair

9. Adjourn

Standards Committee 2010 Roster

Segment 4-2010-11

Chair

Allen Mosher

Senior Director of Policy Analysis and Reliability

American Public Power Association

1875 Connecticut Avenue NW

Twelfth Floor

Washington, D.C. 20009-5715

(202) 467-2944

(202) 467-2992 Fx

[email protected]

Segment 2-2010-11

Vice Chair

P.S. (Ben) Li

President

Ben Li Associates, Inc.

37 Goldring Crescent

Markham, Ontario L6C 1Y6

(647) 388-1498

(905) 887-2235 Fx

[email protected]

Segment 1-2010-11 Carol A. Sedewitz Director, Transmission Planning

National Grid

40 Sylvan Road

Waltham, MA 02451

781-907-2500

781-907-5706Fx

[email protected]

Segment 7-2009-10 John A. Anderson

President & CEO

Electricity Consumers Resource Council

1333 H Street, N.W.

8th Floor, West Tower

Washington, D.C. 20005

(202) 682-1390

(202) 289-6370 Fx

[email protected]

Segment 9-2009-10 Diane J. Barney

Planning Engineer

New York State Public Service Commission

3 Empire State Plaza

Albany, New York 12223-1350

518-486-2943

518-473-2420 Fx

[email protected]

Segment 6-2010-11 Alice Murdock Ireland

Reliability Standard Analyst

Xcel Energy, Inc.

PO Box 1078

Golden, CO 80402

303-273-4832

303-273-4840Fx

[email protected]

Segment 2-2009-10 Terry Bilke

Director, Standards and Compliance

Midwest ISO, Inc.

701 City Center Drive

P.O. Box 402

Carmel, Indiana 46082-4202

(317) 249-5463

(317) 249-5994 Fx

[email protected]

Segment 5-2010-11 Thomas J. Bradish

Director, Reliability Standards

RRI Energy

121 Champion Way

Cannonsburg, Pennsylvania 15317

(724) 597-8593

(724) 597-8875 Fx

[email protected]

Segment 10-2010-11

Linda Campbell

Vice President and Executive Director, Standards and Compliance

Florida Reliability Coordinating Council

1408 N. Westshore Blvd.

Suite 1002

Tampa, Florida 33607-4512

(813) 207-7961

(813) 289-5646 Fx

[email protected]

Attachment 1a SC 2010 Roster

Standards Committee December 9, 2010 Agenda

Segment 5-2009-10 Michael F. Gildea

Director of NERC Compliance

Dominion Resources Services

5000 Dominion Boulevard

(Innsbrook - 3SE)

Glen Allen, Virginia 23060

(804) 273-4624

(443) 213-3679 Fx

[email protected]

Canada David Kiguel

Manager, Reliability Standards

Hydro One Networks, Inc.

483 Bay Street, TCT-15

Toronto, Ontario M5G 2P5

(416) 345-5313

(416) 345-5406 Fx

[email protected]

Segment 8, 2009-10 Brendan Kirby

Consultant

American Wind Energy Association

2307 Laurel Lake Road

Knoxville, Tennessee 37932

(865) 250-0753

[email protected]

Segment 4-2009-10 John D. Martinsen, P.E.

Senior Manager, Reliability Compliance and Regional Transmission

Snohomish County PUD No. 1

P.O. Box 1107

Everett, Washington 98206-1107

(425) 783-8080

(425) 267-6122 Fx

[email protected]

Segment 7-2010-11 Frank McElvain Senior Consulting Manager

Siemens Energy, Inc.

Siemens Power Technologies International

1350 Shorebird Way

Mountain View, CA 94043-1338

650.694.5096

919.365.1356 Fx

[email protected]

Segment 3-2009-10 Ronald G. Parsons

Manager, Transmission Interconnections and Operations

Alabama Power Company

600 North 18th Street

Department ACC

Birmingham, Alabama 35291

(205) 257-3333

(205) 257-3510 Fx

rgparson@

southernco.com

Segment 3-2010-11 Raj Rana

Director - RTO Policy and NERC Compliance

American Electric Power

One Riverside Plaza

Columbus, Ohio 43215

614-716-2359

(614) 223-2352 Fx

[email protected]

Segment 10-2009-10

Steve Rueckert

Director of Standards

Western Electricity Coordinating Council

615 Arapeen Drive -Suite 210

Salt Lake City, Utah 84108-1262

(801) 883-6878

(801) 582-3918 Fx

[email protected]

Segment 1-2009-10 Jason Shaver

Reliability Standards and Performance Manager

American Transmission Company, LLC (262) 506-6885

[email protected]

Segment 8-2010-11 Jim R Stanton SPS Consulting Group Inc.

1707 Brill Drive

Friendswood, Texas 77546

(281) 992-6557

(713) 445-2020 Fx

[email protected]

Segment 6-2009-10 Robert S. Walker

Director, Transmission Management

Cargill Power Markets, LLC

9350 Excelsior Boulevard - MS 150

Hopkins, Minnesota 55343

(952) 984-3747

(952) 984-3763 Fx

[email protected]

Segment 9-2010-11 Klaus Lambeck

Chief Facilities, Siting and Environmental Analysis

Public Utilities Commission of Ohio/the Ohio Power Siting Board

180 E. Broad Street

Columbus, OH 43215-3793

614 644 82 44 614 752 8353 Fx

[email protected]


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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.

Attachment 1b Antitrust Compliance Guidelines


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

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.


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Draft Meeting Minutes Standards Committee

Thursday, November 11, 2010 | 1–4 p.m. Eastern Dial-in Number: 866-740-1260 Participant Code: 4685998

Administrative A conference call meeting of the Standards Committee was held on Thursday, November 11th from 1 p.m.–3 p.m. The agenda, attendance list, and meeting announcement are affixed as Exhibits A, B, and C respectively. Introductions and Quorum Standards Committee Chair Allen Mosher led the introduction of committee members and determined there was a quorum. NERC Antitrust Compliance Guidelines Maureen Long reviewed the NERC Antitrust Compliance Guidelines. Meeting Agenda Jim Stanton motioned to approve the agenda as distributed with the following items added:

Add a discussion on the quality review associated with an informal posting

Add an item for action by the SC’s Executive Committee to approve a field test for BAL-03 - Frequency Response.

The motion was approved without objection or abstention.

Waiver of 5-day Rule Terry Bilke motioned to waive the 5-day Rule.

– The motion was approved without objection or abstention.

Consent Agenda Raj Rana motioned to approve/ratify the following items from the consent agenda:

October 13-14, 2010 Standards Committee Meeting Minutes

October 28, 2010 Executive Committee Meeting Minutes

Attachment 2a Standards Committee November 11, 2010 Draft Meeting Minutes


Standards Committee Draft Meeting Minutes November 11, 2010

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Status of High Priority Projects David Taylor provided an overview of the status of high priority projects, with a particular emphasis on those high priority teams that are behind schedule and the Standards Committee discussed those high priority projects currently behind schedule. Status of High Priority Activities and Open Action Items

Allen Mosher reviewed the list of high priority activities selected for Standards Committee attention in 2010, and the status of open action items. He indicated that some items will continue into 2011.

Standards Actions

SAR for Revisions to CIP-005-3 - Cyber Security — Electronic Security Perimeter – Authorize Posting the SAR and Proposed Standard for a 30-day Formal Comment Period, with Revisions to the Already Formed Ballot Pool During the first 20 days and an Initial Ballot During the Last 10 days of that Period

Linda Campbell motioned to authorize use of the expedited standard development process in support of the reliability-related need to provide greater clarity to the requirements in CIP-005 associated with remote access, and:

Authorize posting a SAR that contains a set of proposed revisions to CIP-005-3, and an associated reference document for a 30-day formal comment period

Direct staff to open the existing ballot pool for the first 20 days of the 30-day comment period

Direct staff to conduct an initial ballot during the last 10 days of that comment period.

Include a quality review during the 20-day comment period and report the results to the Standards Committee and the Standard Drafting Team, with the team to make any necessary changes before the recirculation ballot

The motion was approved with Jason Shaver, David Kiguel, and Alice Ireland opposed, with no abstentions.

Project 2010-13 – Relay Loadability Order 733 Phase II – Appoint a drafting team; direct staff to solicit additional nominations

Jason Shaver motioned to appoint the following to the drafting team; direct staff to solicit additional nominees to provide greater diversity and expertise; delay recommending appointment of a chair until after the initial meeting of the team:

Benson Giang Vuong, Salt River Project


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Sudkir Thakur, Exelon Generation Company, LLC (Exelon Nuclear)

Xing Chen, BC Hydro

Mike Jensen, Pacific Gas & Electric

Jeff Billo, ERCOT

Jonathan Hayes, SPP


Project 2010-11 – TPL Table 1 - Footnote ‘b’ – Authorize posting for comment and an initial ballot

Carol Sedewitz motioned to:

Authorize posting the revision to ‘Table 1 Footnote b’ for a 45-day comment period;

Direct staff to form a new ballot pool during the initial 30 days of the 45-day comment period; and

Direct staff to conduct an initial ballot during the last 10 days of the 45-day comment period.


Project 2007-07 - Vegetation Management – Authorize posting for comment and a successive ballot

The drafting team was asked to work with staff to resolve as many issues as possible and then resubmit the revised standard.

Project 2009-03 — Emergency Operations – Authorize Moving the SAR Forward to Standard Drafting; Appoint the SAR Drafting Team to Serve as the Standard Drafting Team

Carol Sedewitz motioned to authorize moving the Emergency Operations SAR forward to Standard Drafting; and appoint the SAR Drafting Team to serve as the Standard Drafting Team.


Coordination

NERC Board of Trustees Activities Relative to Standards

Allen Mosher provided a summary of the items discussed during the November 3, 2010 Members Representative Committee.

A key item was a discussion of the Reliability Standard Development Plan, and a conclusion that this should be a ‘living’ document rather than a plan with an annual update. The Standards Committee’s Process Subcommittee needs to complete its work with its project prioritization tool for review and endorsement at the December, 2010 Standards Committee meeting. The project prioritization tool


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needs to absorb the work in prioritizing outstanding regulatory directives. The goal is to complete the prioritization of projects in the Reliability Standards Development Procedure 2011-2013 prior to the February 2011 Reliability Summit and then seek approval at the February 17, Board of Trustees meeting.

Update on Regulatory Activities

Holly Hawkins provided an update on regulatory activities.

Coordination with the Technical Committees

David Taylor provided an update on his work with NERC’s Standing Committees Coordination Group in identifying studies and analyses that the technical committees could perform prior to the initiation of a project previously identified in the Reliability Standards Development Plan.

The Standards Committee endorsed Dave’s proposal.

Other Items

Update on Annual SC Elections

Maureen Long provided an update on the status of Standards Committee elections for the 2-year term 2011-2013. There are nominees for all segments except for Segment 9. Several segments have only one nominee and don’t require any formal election process; segments with multiple nominees will begin balloting November 12, 2010.

Informal Postings and Processing Lower Priority Projects

Carol Sedewitz led a discussion on quality reviews prior to informal postings and the dilemma associated with projects underway that are not identified as ‘high priority projects.’ With staff focused solely on high priority projects, there isn’t a process in place to move lower priority projects forward for either an informal comment period or for a formal comment period that requires staff resources to update web pages, write announcements, develop and process comment forms, and verify the accuracy of responses to comments in comment reports.

Executive Committee Actions

Terry Bilke motioned to preauthorize the SC’s Executive Committee to act on the following if they come to the Executive Committee for action before December 9, 2010:

i) Project 2007-17 – Protection System Maintenance and Testing - Authorize posting for comment and a successive ballot

ii) Project 2008-06 – Cyber Security 706 – authorize use of the Expedited Process

iii) Project 2007-07 - Vegetation Management – Authorize posting for comment and a successive ballot


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The Executive Committee may also take action to approve a field trial of BAL-003 – Frequency Response

Adjourn


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Draft Meeting Minutes Standards Committee’s Executive Committee

Wednesday, November 24, 2010 10:00 a.m. (Eastern) Administrative Items Chair, Allen Mosher introduced those on the conference call and determined that there was a quorum with four of the five members of the Executive Committee participating in the call (three are needed for a quorum):

Allen Mosher David Kiguel Michael Gildea Jason Shaver

Also participating in the call were the following:

Holly Hawkins Scott Mix Howard Gugel Maureen Long David Taylor Herb Schrayshuen John Lim

NERC Antitrust Compliance Guidelines and Open Call Reminder Maureen Long reminded those participating of their obligation to comply with the Antitrust Compliance Guidelines and to be cognizant that conference calls are open to all interested parties.

Action Item Project 2008-06 – Cyber Security Order 706 - Authorize an Action Plan to Complete the CIP Version 4 Standards by December 31, 2010

The following schedule was proposed to meet the December 31, 2010 deadline for completing the CIP Version 4 Standards:

Conduct an abbreviated comment period with a successive ballot during the same period, from December 2-11, 2010. (The comment and ballot period would coincide with the ballot for the

Attachment 2b SC Executive Committee November 24, 2010 Meeting Minutes


SC Executive Committee Meeting Minutes November 24, 2010

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Expedited Revisions to CIP-005-4 that begins December 2. This will synchronize these projects. The response from industry that we received from the first ballot was that Industry was confused by the two projects. This will help relieve that confusion.)

Wednesday December 1, 2010 – Hold an industry webinar on CIP Version 4 explaining the

changes that were/were not made and why – hosted by NERC staff, not the team

Thursday December 2, 2010 – Open a 10-day formal comment period and conduct a successive ballot for CIP Version 4 (Initial ballot for Expedited Revisions to CIP-005-4 conducted during same 10-day period)

Sunday December 12, 2010 – Friday Dec 17 – SDT prepares summary response to comments and

possible changes to CIP-002-4 (Expedited Revisions to CIP-005-4 team prepares response to comments and possible changes to CIP-005-4)

Friday December 17 – Sunday Dec 19, 2010 – Staff and others conduct quality review (if SDT has made any significant changes) and finalize all documents for CIP Version 4 (Conduct quality review if SDT has made any significant changes and finalize all documents for Expedited Revisions to CIP-005-4)

Monday December 20 – Thursday December 29, 2010 – Conduct recirculation ballot of CIP

Version 4 (Conduct recirculation ballot of Expedited Revisions to CIP-005-4)

Obtain BOT approval and file with regulatory authorities in January, 2011

Michael Gildea motioned to authorize posting the CIP Version 4 Standards and associated implementation plans for an abbreviated comment period with a parallel successive ballot; allow the team to make significant changes between the successive and recirculation ballots with a goal of completing the recirculation ballot before the end of December, 2010.


Adjourned

S - SC Report 1

S Purpose Chair Status

Explanation of Difference

Between Plan and

Estimate

Plan for Returning Project

to Schedule or Expediting

the Project Top 3 Issues

Standard

s

Involved

Priority: Urgent(17)

Name: Project 2006-02: Assess Transmission Future Needs(1)

Owner: Edward Dobrowolski(1)

Requires assessmentsand plans to determine ifthe bulk power systemmeets specifiedperformancerequirements undervaried theoreticaloperating conditions tomeet present and futuresystem needs.

John Odom, FRCC The SDT has completedresponding to commentsfrom a fifth (informal)posting. It is waiting forresolution of the footnote'b' issue prior to movingto ballot.

Project was on scheduleuntil the initial ballotfailed. It is currently onschedule for the revisedproject. However, the E-2 and E-9 FERC rulings ofMarch 18, 2010 have adirect bearing on TPL-001-2 and resolution ofthose items may cause aproject delay.

TPL-001-2 is presently inlimbo awaiting resolutionof footnote 'b' issues. Allother comments havebeen addressed and theSDT can't proceed anyfurther at this time.

On the footnote 'b' path,the ballot process startedon 11/19/10. .

1. Non-ConsequentialLoad Loss2. P5 event description3. Relay & Load Modeling4. Spare EquipmentStrategy

TPL-001throughTPL-006

Name: Project 2006-06 Reliability Coordination(1)

Owner: Stephen Crutchfield(1)

To ensure that thereliability-relatedrequirements applicableto the ReliabilityCoordinator are clear,measurable, unique andenforceable; and toensure that this set ofrequirements is sufficientto maintain reliability ofthe Bulk Electric System.

Mike Hardy (SoCo) The RCSDT receivedcomments based on thequality review. The teamcompleted its review andrevision of the standardsand re-submitted thedocumentation forpresentation to the SC atits December meeting.

IROO-003 was added tothe project scope and aposting for commentsended September 3. Theinclusion of IRO-003under this project is notreflected in the projectschedule. The teamanticipates handlingrevisions to IRO-003separately from the restof the project. TheRCSDT is responding tocomments anddiscussing revisions toIRO-003. the team willmeet January tocomplete the response tocomments anddetermine next steps.

The first draft of thesestandards was posted forindustry comment in thethird quarter of 2008 andthe second draft wasposted in the thirdquarter of 2009. Thisproject began twomonths later thanoriginally anticipated asNERC added staffcoordinators and thedrafting of the revisedstandards required morework and coordinationwith other projects thanoriginally anticipated.The drafting team hasalso determined that athird comment period willbe necessary for this setof standards.

The RCSDT plan torequest that the projectbe moved to ballot at theSeptember 2010 SCmeeting.

1. Definitions forReliability Directive,InterpersonalCommunications and theuse of three partcommunications.2. Coordination withOPCPSDT

Com-001,COM-002, IRO-001, IRO-002, IRO-005, IRO-014, IRO-015, IRO-016; IRO-003 wasrecentlyaddedunder asupplementalSAR

Name: Project 2007-01 Underfrequency Load Shedding (1)

Owner: Stephanie Monzon(1)

S - SC Report 1 Page 1 12/1/10 1:27 PM

longm

Text Box

Attachment 3a Project Status Standards Committee December 9, 2010 Agenda



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Project 2007-01Underfrequency LoadShedding 3-2010 Rev 00Imported from MS Project

Robert J. O'Keefe (AEP) Preparing regulatoryfiling

No schedule difference PRC-006-0, PRC-007-0,PRC-009-0EOP-003

Name: Project 2007-02 Operating Personnel Communication Protocols(1)

Owner: Harry Tom(1)

Project 2007-02Operating PersonnelCommunication Protocols

Requires developing newrequirements in supportof blackoutrecommendation #26 toensure that real-timesystem operators usestandard communicationprotocols during normaland emergencyoperations.

Lloyd Snyder The OPCP SDT wastrained on Results Basedstandards development.The outcome of the RCSDT effort to define anew NERC Glossary termfor "reliaiblity directive"is planned for initialballot in December 2010.The OPCP SDT agreed touse the definition in itsproposed new standardCOM-003-1 uponfinalization by the RCSDT.

The project is late for thefollowing reasons:1) Standards Committeepulled the draft standardfrom its Formal Commentperiod.2) Differences of opinionover the inclusion ofAlert Level Guidelines inthis standard3) The OPCP SDT agreedto use the RC SDTproposed definition of"reliability directive" inits proposed newstandard COM-003-1upon finalization by theRC SDT. The outcome ofthe RC SDT effort todefine a new NERCGlossary term for"reliaiblity directive" isuncertain.

The SDT plans to requestconcurrent Comment andBallot period as the nextdevelopment step.

1. Recent NERC Advisoryon the use of three-partcommunications for""directives"" hassparked industry interestand controversy. COM-003 will need to addressthese issues as a result.2. Specifying CentralStandard Time as"official" time forcommunications on acontinent-wide basis.3. Use of NATO alphabetmay prove difficult togain industryacceptance.

COM-003-1

Name: Project 2007-03: Real-time Operations(1)





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Requires upgrading andexpanding existingrequirements thataddress balancingauthority responsibilitiesto ensure a balancebetween load,interchange andgeneration within itsbalancing authority areain support ofinterconnectionfrequency. Requiresupgrading and expandingexisting requirementsthat addresstransmission operatorresponsibilities to ensurethe real-time operatingreliability of thetransmission assetswithin the transmissionoperator’s area.

James S. Case (Entergy) The SDT has finished theresponse to commentsand is looking to moveforward to ballot.However, FERC staff hasrequested anothermeeting with the SDTand any move towardballot is on hold pendingthe results of thatmeeting.

This project was onschedule until theDecember 2009meetings with FERC staff.As a result of thosemeetings, a 4th postingwas deemed necessaryand the original schedulewas revised to reflectsame. The project wason schedule against thatrevision but is nowlagging while the SDTwaits to meet with FERCstaff.

FERC staff has beencontacted to see if theywant another meeting - aresponse was promisedno later than October1st. The meeting hasnow been set for Dec.15th,

1. Elimination of howtype, good utilitypractice, & certificationrequirements.2. Controversy overSOL/IROL approach.3. Validity of dataspecification approach.

PER-001& TOP-001through -008

Name: Project 2007-07 Vegetation Managment(1)

Owner: Harry Tom(1)

Requires upgrading theexisting requirements forentities to implement avegetation managementprogram to preventtransmission outagesthat adversely impactthe reliability of the bulkelectric system.

Richard Dearman (TVA) The VM SDT consideredNERC staff commentsand prepared draftversion 5c6 for StandardsCommittee ExecutiveCommittee action onNovember 29, 2010.

Delay due todisagreement over VSLassignments for R1/R2and technical content inthe draft that could beviewed as weakening thestandard. The issues ofActive Transmission LineRight of Way, CriticalClearance Zone, Galletand compliance elementsare undergoing debateand resolution.

The VM SDT consideredNERC staff commentsand prepared draftversion 5c6 for StandardsCommittee ExecutiveCommittee action onNovember 29, 2010.

1. Active TransmissionLine ROW may be viewedas weakening ofstandard2. Critical clearance zoneneeds to be emphasizedin version 23. VSLs for R1/R2 may beviewed as weakening ofstandard

FAC-003-1TransmissionVegetationManagement

Name: Project 2007-09 Generator Verification(1)

Owner: Harry Tom(1)




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Project 2007-09Generator Verification

Requires upgradingexisting requirements forgenerators to verify theircapabilities to ensurethat accurate data isused in model to assesthe bulk electric system.

Lee TaylorKen StenroosDave Kral

SDT is reviewing NERCstaff feedback andworking to modifyverbiage to addressenforceability concerns.

The primary reason forthe schedule differencefor PRC-024-1 iscommentary from FERCstaff that the standard bemore performanceoriented. The SDTcompletely overhauledthe initial draft toaccomodate thefeedback.The MOD-024. Mod-025,MOD-026 and MOD-027standards haveundergone major re-structuring based uponNERC commentsreceived during the initialcomment period.MOD-024 will becombined with MOD-025and the requirementshave been revised to besimpler to understandand to enforce. Thiseffort took many monthsto complete.

SDT is working to modifyverbiage to addressenforceability concerns.Posting documents willbe prepared during nextteam meeting in earlyFebruary 2011. Theexpected date for entirepackage is February 15,2011.

1. Applicability issueregarding sub 100kVconnected generatorsand whether to includesynchronous condensersamong the facilities thatmust comply with MOD-025.2. Based on promptingfrom FERC staff, PRC-024is being modified to bemore generatorperformance oriented.3. Alleged duplication ofrequirements betweenMOD-010/MOD-012 andMOD-025.

MOD-024-1MOD-025-1MOD-026-1MOD-027-1PRC-019-1PRC-024-1

Name: Project 2007-12 Frequency Response(1)

Owner: Darrel Richardson(1)

Project 2007-12Frequency ResponseImported from MS Project

Bill Herbsleb (PJM) The SDT is review thefollowing documnetsprior to a formal posting:1) BAL-003-1 DraftStandard2) BAL-003-1Implementation Plan3) BAL-003-1 BackgroundDocument4) BAL-003-1 CriteriaUsed to Select FrequencyEvents5) BAL-003-1 Field TestDocument

1) Development of amethodology forcalculating theInterconnection FreuencyResponse Obligation2) Development of amethodology fordistributing theInterconnectionFrequency ResponseObligation to the BA

BAL-003-0FreuencyResponse andFrequency Bias

Name: Project 2007-17 Protection System Maintenance and Testing(1)

Owner: Al McMeekin(1)




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Transmission andGeneration ProtectionSystem Maintenance andTesting, to consolidatePRC-005-1, PRC-008-0 —Underfrequency LoadShedding EquipmentMaintenance Programs;PRC-011-0 — UVLSSystem Maintenance andTesting; and PRC-017-0— Special ProtectionSystem Maintenance andTesting into a singlemaintenance and testingstandard. Standards PRC-008-0, PRC-011-0, andPRC-017-0 would then bewithdrawn.

Charles W. Rogers,Consumers Energy

Documents for thedefinition of ProtectionSystem were posted for30-day comment andsuccessive ballot on9/13/10. The ballotrecord is as follows:Quorum: 84.11 %Approval: 84.52 %. Thedefinition will proceed torecirculation ballot.

The definition passedthe recirculation ballotwith an 86.83% approval.The NERC BOT approvedthe new Defintion ofProtection System at itsNovember meeting andthe FERC filingdocuments are beingprepared. Theassociated standarddocuments for PRC-005-2were revised by the SDTbased on comments,questions, andrecommendations perNERC staff qualityreview, and were postedfor a 30-day commentperiod with 10-daysuccessive ballot thatbegan November 17 andends December 17,2010.

The StandardsCommittee approvedexpediting the timelineof this project in hopes ofpresenting the industryapproved standard to theBOT for board action atits August meeting. Toaccomplish this, the SCset the followingschedule:•SC approves motion toexpedite completion ofprojects (June 10, 2010)•Conduct 36-day formalcomment periodconcurrent with ballot•Formal Comment period(June 11, 2010–July 16,2010)•Assemble Ballot Pool(June 11, 2010–July 2,2010)•Conduct 10-day Ballot(July 7–16, 2010)•Teams Respond toComments (July 16–23,2010)•Permit modifications torequirements to improveconsensus and addresscomments.•Conduct 10-day finalballot (July 23,2010–August 2, 2010)•Present to board foraction (August 5, 2010)

The Team met August 24-26, 2010 in Novi, MI @ITC. The teamresponded to industrycomments from theconcurrent formalcomment and ballotperiod (June 11,2010–July 17, 2010), andfrom the recirculationballot of the reviseddefinition of ProtectionSystem (July 23,2010–August 2, 2010).The Chair will work withthe NERC Coordinator tofinish development of theVRFs and theirjustifications. Documentsfor the definition ofProtection System will beprepared and presentedto NERC staff the week ofAugust 30, 2010 for a 15day ballot. Documentsfor the definition ofProtection System wereposted for 30-daycomment and successiveballot on 9/13/10. Thedefinition was approvedand will proceed to therecirculation ballot.Documents for thestandard will be revisedper the Quality Reviewand presented to NERCstaff the week ofNovember 8, 2010 for 30-day comment andsuccessive ballotbeginning mid-November.

1. FERC Order 693directive to establishmaximun allowableintervals.2. NERC staff positionson issues emerging fromProject 2009-10.3. Being charged with aviolation if late onmaintenance due to anatural disaster.

PRC–005-1 —Transmission andGenerationProtection SystemMaintenance andTestingPRC–008-0 —UnderfrequencyLoadSheddingEquipmentMaintenanceProgramsPRC–011-0 —UVLSSystemMaintenance andTestingPRC–017-0 —SpecialProtection SystemMaintenance andTesting

Name: Project 2008-01 Voltage and Reactive Planning and Control(1)





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Revise the VARStandards to require thatappropriate functionalentities develop andcoordinate voltage andreactive planning andoperating criteria toensure that there aresufficient reactiveresources, and voltageand reactive margins, tomanage the risk ofvoltage instability.

John Simpson - ChairBill Harm - Vice Chair

The team continueddeveloping requirementsand measures for theproject. The team has awork plan to continuedeveloping theRequirements andMeasures, Backgroundand Guidelines /Technical Basis sectionsfor three proposedstandards. The draftswill be discussed andfinalized on a webmeetings scheduled forNovember 30. Once thestandards are prepared,the team plans a 30 dayinformal comment periodin the January / February2011 timeframe.

TBD VAR-001,VAR-002

Name: Project 2008-06 Cyber Security Order 706 (1)

Owner: Howard Gugel(1)




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The second phase (Phase2) of Project 2008-06Cyber Security Order 706will require the SDT topropose modificationsnot included in Phase 1of the project to bringthe following standardsinto conformance withthe ERO Rules ofProcedure and to addressthe directives from FERCOrder 706:CIP-002-2 Critical CyberAsset IdentificationCIP-003-2 SecurityManagement ControlsCIP-004-2 Personnel &TrainingCIP-005-2 ElectronicSecurity Perimeter(s)CIP-006-2 PhysicalSecurity of Critical CyberAssetsCIP-007-2 SystemsSecurity ManagementCIP-008-2 IncidentReporting and ResponsePlanningCIP-009-2 Recovery Plansfor Critical Cyber Assets

John Lim (ConsolidatedEdison Co. of New York)

Philip Huff (ArkansasElectric CooperativeCorporation)

SDT continues to reviewand evaluate its schedulefor completingmodifications to CIP-002by year's end and theproject by the end of2011. The Phase 2 workrepresents a significantshift in industry approachand strategy for cybersecurity. Review ofindustry informalcomments on the initialdraft of the new CIP-002-4 has been completed,and the SDT preparednew, revised standardsbased on the inputsreceived. The new,revised standards havebeen renumbered toindicate the significanceof the departure from thepreviously approvedversion (CIP-002-3through CIP-009-3). Thenumbering for the newstandards is CIP-010-1and CIP-011-1.

The new standards wereposted for informalindustry comment as apackage in early May2010. TechnicalWorkshop were held May19-20, 2010 to providethe SDT with anopportunity to explainthe drafts of the newstandards and to gaininitial industry input onthe drafts.

Based on informalcomments and workshopfeedback, the teamneeds to continueworking on CIP-011. Inorder to addressconcerns about gaps incoverage, the team hasdeveloped CIP-002-4 toreplace the current risk-based methodology withbright-line criteria. Theplan is to have industryapproval and filed withFERC by end of 2010.

N/A N/A 1. The team is large (24members) and observerparticipation issignificant (10-20 at anygiven meeting). Newmembers with planningand operationsexperience are beingadded to the team toprovide electric systemexpertise.2. Finalizing a process tocategorize the BES CyberSystems to provideappropriate and effectivelevels of cyber securitycontrols and protection.3. Developing a CIP-002-4 that industry willaccept and meetsexternal expectations.Also some members feelthat CIP-002-4 is notenough, even as apreliminary measure.

CIP-002-2 CriticalCyberAssetIdentificationCIP-003-2SecurityManagementControlsCIP-004-2Personnel &TrainingCIP-005-2ElectronicSecurityPerimeter(s)CIP-006-2PhysicalSecurityofCriticalCyberAssetsCIP-007-2SystemsSecurityManagementCIP-008-2IncidentReporting andResponsePlanningCIP-009-2RecoveryPlans forCriticalCyberAssets




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The new CIP-002-4 wasfinalized at theSeptember meeting andwas posted for industrycomment and assemblyof the ballot body onSeptember 20. Theresults of the ballot andcomments were analyzedand the team updatedthe bright-line criteria atits face-to-face meetingin November. This newCIP-002-4 was posted forindustry comment andballot on November 30.Comments and ballotsare due December 11.The team will respond tocomments and preform arecirc ballot following theclose if the ballot period.

Name: Project 2009-01 Disturbance and Sabotage Reporting(1)


Project 2009-01Disturbance andSabotage ReportingImported from MS Project

Robert D. Canada (SoCo)Brian Evans-Mongeon(Util. Svcs.)

The team will meet inDecember and January toaddress commentsreceived during theinformal comment periodwhich ended October15th. The drafting teamwill revise the standardbased on the commentsreceived and craftCompiance elements fors subsequent posting..

Comments received onthe SAR indicate apotential need to developtechnology tools tofacilitate reporting to allappropriate entities. Athird standard commentperiod was added to theproject schedule as wellas longer developmenttimes for the first andsecond drafts of thestandards.

1. Funding fortechnology solutions forreporting.2. Coordination withNERC EAWG3. Requirementspertaining to the EROand gaining stakeholderconsensus.

EOP-004,CIP-001and CIP-008

Name: Project 2009-02: Real-time Reliability Monitoring and Analysis Capabilities(1)


The new standard orstandards will establishrequirements for thefunctionality,performance, andmanagement of Real-time tools for ReliabilityCoordinators,Transmission Operators,and Balancing Authoritiesfor use by their SystemOperators in support ofreliable Systemoperations.

Sam Brattini, KEMACharles Abell, Ameren

The SC has removed thehold on this project and itis in the process of re-starting. .

The SC has turned thisproject back on but it iswaiting on the schedulingof a Leadership Meetingto get it officially started.

N/A 1. Balancing betweenspecific tools and genericcapabilities.2. Coming up withrealistic and acceptableperformance metrics.3. Avoiding conflict withcertification process.

New




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Name: Project 2009-03 Emergency Operations Planning(1)





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EOP-001-0, EOP-002-2,and EOP-003-1 wereVersion 0 standards withminimal updates. Theyeach have requirementswith applicabilities thatare inconsistent with thefunctional model, as wellas various words orelements that needclarification. IRO-001-1has requirements withapplicability and clarityissues that must beaddressed and somerequirements they maybe moved to the newEOP standard(s).The EOP standards in thelist above shall beclarified individually,reorganized, or mergedinto a single standard.IRO-001 was originally apart of this project buthas been removedbecause all of the issuesand directives associatedwith that standard havebeen addressed by theReliability CoordinationSDT, Project 2006-06.

The development shallincorporate the NERCBOT approvedinterpretations, FERCdirectives, and otherimprovements to thestandards deemedappropriate by thedrafting team consistentwith establishing highquality, enforceable andtechnically sufficient bulkpower system reliabilitystandards.

Robert Staton, XcelEnergy

Scheduling the SAR DTLeadership meeting to beheld in Princeton thissummer. Meeting isscheduled for August 11,2010.The SAR DT Leadershipmeeting was held inPrinceton on August 11,2010. TheChair, Vicechair, and members ofNERC and FERC staffparticipated. AReadyTalkweb/conference call isscheduled for August 31for the entire SDT.

The first Drafting Teammeeting was heldOctober 26-28, 2010 inGolden, CO. hosted byXcel Energy. The SARwas modified based onindustry comment and allindustry comments wereaddressed.Documentation has beensubmitted to NERC stafffor review prior tosubmittal to the SC formoving the SAR into thestandards developmentstage and the responsesto the industrycomments will be posted. The SAR was approvedby the StandardsCommittee at theirNovember 2010 meetingand the project willproceed to the standarddevelopment phase. TheSC also approved theSAR drafting team toserve as the standarddrafting team. LauraZotter, a member of thesdt is no longer withERCOT and must bereplaced. Arecommendation for herreplacement has beensubmitted by ERCOT andwill be presented to theSC at their Decembermeeting.

First available meetingdates due to SDTleadership schedulingconflicts.

Further development willdepend on disposition ofthis project by theStandards Committee tobe determined at theirDecembeer meeting.

EOP-001-0 —EmergencyOperationsPlanningEOP-002-2 —CapacityandEnergyEmergenciesEOP-003-1 — LoadSheddingPlansIRO-001-1 —ReliabilityCoordination —ResponsibilitiesandAuthorities

Name: Project 2010-10 FAC Order 729(1)




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Owner: Darrel Richardson(1)

Project 2010-10 FACOrder 729 - Modify FAC-013-1 to address Order729 directives

Robert Peirce (Duke) The standard is comingout of ballot. The Teamis meetng the week ofNovember 8 to addresscomments received.

FAC-012-1TransferCapabilityMethodologyFAC-013-1EstablishandCommunicateTransferCapabilities

Name: Project 2010-12 693 Directives(1)

Owner: Andy Rodriquez(1)

This project is intendedto develop rapidresponses to non-controversial directivesusing an expeditieddevelopment process.

Ben Li Balloting concluded. 6standards related to 11directives approved.

Several

Name: Project 2010-13 Relay Loadability Order(1)

Owner: David Taylor(1)




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Project 2010-13 RelayLoadability Orderinvolves modifying thePRC-023-1 TransmissionRelay Loadabilitystandard and maybeother standards incompliance with theFERC Order 733 issuedon March 18, 2010.

Charles Rogers,Consumers Energy

• Posted PRC-023-2 withAttachment B(applicability test) for the45-day formal commentperiod with concurrentballot on November 1,2010• Held industry technicalwebinar on PRC-023-2 onNovember 23, 2010, withapproximately 90participants viaReadyTalk.• Received nominationsfor Phase II DraftingTeam and obtainedStandards Committeeappointment ofrecommendedcandidates.• Obtained approval fromthe StandardsCommittee to seekadditional members withspecific expertise for thedrafting team from FRCC,NPCC, or MRO, andpreferably someone withstandards draftingexperience.• Successfullytransitioned project fromStephanie Monzon to JoeBucciero

• Phase I is moving onschedule to meet theFERC filing directive ofMarch 18, 2011• Phase II is starting alittle later than planneddue to resourcerequirements for Phase Icompletion

Phase I• Posting with concurrentballot occurred onNovember 1, 2010 andthe schedule for re-posting and re-ballotingis very tight.

Phase II• The Phase II effort isstarting in January 2011instead of October 2010,but steps are being takento improve the timing forthis phase of the project.

• Phase I – Pendingresponse to Request forClarification and PossibleRehearing – impact onthe overall scheduleparticularly on thedevelopment of theapplicability test• Phase I – The projectschedule is veryaggressive.• Phase II - Start date iseffectively January 2011requiring a high-level ofcommitment of time andresources from thedrafting team membersto avoid a schedule delay

PRC-023-1TransmissionRelayLoadability

Priority: Normal(9)

Name: Project 2006-04: Backup Facilities(1)


Requires upgrading andexpanding existingrequirements to ensureentities have sufficientback-up capabilities tosupport continuedreliable operations.

Sam Brattini, KEMA The project received BOTapproval and is nowready for filing. .

The project was on itsoriginal schedule until itwas remanded back tothe SDT by the StandardsCommittee despite asuccessful initial ballot.It is now on schedule forthe revised schedulesubmitted following thatremand.

The project is ready to befiled by Legal.

1. Length of time to getbackup up and running.2. Length of time to re-establish backupcapability.3. Need for GOP to havebackup facility.

EOP-001& EOP-008

Name: Project 2006-08 Transmission Loading Relief(1)





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Ensures that criticaltransmission systemlimits are relieved within30 minutes. The TLRproject has been dividedinto three phases:

Phase 1 — A coordinatedeffort with NAESB toclarify and refine thesteps in theTransmission LoadingRelief Procedure for theEastern Interconnectionto reaffirm the stepsneeded to supportreliability and the stepsneeded to support thebusiness practice.

Phase 2 — A second setof modifications to thestandard involves furtherconsideration of achange to the marketflow calculation specifiedin PJM/MISO and SPPregional differences E.1and E.2 in Standard IRO-006-03 to address areliability issue whenMISO, PJM and SPP areunable to meet theirrelief obligations duringTLR.

Phase 3 — A third set ofmodifications to includethe changes needed toelevate the overallquality of the standardand to address theadditional technicalissues that have beenposed with this standardby stakeholders andFERC.

Ben Li (Ben Li Assoc.)Jim Busbin (SoCo)

Phase I has beenaccepted by theCommission and aRulemaking issued.

Phase II has beencompleted. As the onlychanges being developedin response to the FieldTrial are modifications toNAESB standards, nofurther action is required.

Phase III has beenapproved by the BOT andwill be filed in late2010/early 2011.

This project was delayeddue to resourceconstraints.

Based on WECC orderrelated to their regioanlstandard, we may wantto hold filing until wehave coordinatedresponses/filings withWECC and ERCOT.

IRO-006-5IRO-006-EAST-1

Name: Project 2007-05 Balancing Authority Controls(1)





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Project merged withRBCSDT.

Larry Akens (TVA) The Balancing AuthorityControls project has beencombined with Project2007-18 Reliability BasedControls project. A newproject schedule for thecombined teams will bedeveloped by the newcoordinator as part ofProject 2010-14Balancing AuthorityReliability-based Control.

BAL-002BAL-004BAL-005BAL-006

Name: Project 2007-06 System Protection Coordination(1)





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Requires upgrading andexpanding the existingrequirements to identifycriteria for determiningwhere to installprotection systemdevices and for requiringthe installation of thosedevices to protect thereliability of the bulkelectric system. Study toidentify criteria for whereto install protectionsystems has not beendone. The standard isbeing revised minus thiscriteria

Philip Winston, GeorgiaPower Company

The team is in theprocess of revising thedocuments per NERCstaff's review andrecommendations forimprovement. PhilWinston and Al McMeekinhad a conference callwith FERC staff on Friday,August 20, 2010 todiscuss the team'sprogress and directionand obtain FERC staff'sopinions on both. Themeeting was productiveand Phil and I will followup with the team.TheSDT held awebconferenceSeptember 29, 2010 tocontinue work onrevising documents perthe NERC quality review.Meeting with PhilWinston on November 30and December 1, 2010 torevise documents per theNERC quality review.

Work on this project isbeing done as timepermits. It is currentlynot a high priorityproject.

1. Should this standardinclude the"coordination"requirement of allprotection systems?UFLS and UVLS arecovered by otherstandards- FERC Staffhas concerns that thisstandard should cover allcoordination and otherstandards may be usedto supplement the basicrequirement.2. Existing protectionsystems do they need tobe re-evaluated whenstandards goes intoeffect (most have beenoperating properly formany years)? Use ofimplementation plan orpeer review? Theindustry has greatconcern about having toconduct studies to showcoordination of existingsystems (the argument isthat the protectionsystems are currentlyworking properly andhave been so that shouldbe proof enough ofcoordination. Also howoften is this done?) Thedrafting team has alsoadded a provision thatrequires the appropriateentities to exchange theinformation for all tiepoints and where theinformation is different(from that which is in therecords of the receivingentity) new studies arerequired similar to thoserequired for newadditions and/orchanges.3. Addressing the"supplemental SAR"assigned by the SC.

PRC-001-1

Name: Project 2007-11 Disturbance Monitoring (1)

Owner: Stephanie Monzon(1)




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Project 2007-11 DME2010-03 Rev 00 Importedfrom MS Project

Mr. Jeff Pond Oct. 2010 - The SDTcompleted the secondversion of the standardand planned onsubmitting thedocuments for aninformal posting;however, time does notpermit posting thestandard informally dueto the amount of activityoccurring with the highpriority projects. NERCstaff indicated that itwould be at least 6months before thestandard would beposted for industryreview.

The team was challengedto come up withtechnical justification forthe requirements in thestandard.

The team assembled atask team that iscollecting data(voluntary) andperforming a correlationanalysis. This analysis iscomplete.

- Since this is not apriority project and NERCstaff indicated that thestandard could not beposted for another sixmonths the projectschedule will slipapproximately 8-10months.- With this scheduledelay the SDT will haveissues with keeping themomentum forward.

PRC-018,PRC-002

Name: Project 2007-23 Violation Severity Levels(1)

Owner: Howard Gugel(1)

The project team hasbeen called back tomodify the VSLs basedon the June 19 FERCOrder on the VSLs. Thereis substantial work to bedone in order to applythe Guidelines the FERCadded for assigningVSLs. Also there is anissue on the VSL for socalled binaryrequirements (ones thatare pass or fail) thatshould be consistentlyclassified as Severe andif not provide goodsupport as to why. Theteam is proposing achange to the penaltytable for binaryrequirements.

NERC staff proposedVSLs and a supplementalSAR were posted forcomment through Sept16. The projectcoordinator will bemeeting with some VSLvolunteers for a few daysafter the close of thecomment period torespond to commentsand make conformingchanges based on thecomments. They thenbrought this to theStandards CommitteeExecutive Committeearound Sept 20 with arequest to post for pre-ballot review. The VSLswere posted for pre-ballot review onSeptember 27. Ballot willended November 6.VSLs were approved bythe BOT. Expect to filewith FERC December 2.

Multiplestandards thathave donot haveVSLsfiled withthecommission

Name: Project 2008-12 Coordinate Interchange Standards(1)





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Revise the set ofCoordinate Interchangestandards to ensure thateach requirement isassigned to an owner,operator or user of thebulk power system, andnot to a tool used tocoordinate interchange;to address theInterchangeSubcommittee’sconcerns related to theDynamic Transfers andPseudo-ties, to addresspreviously identifiedstakeholder commentsand applicable directivesfrom Order 693; and tobring the set ofCoordinate Interchangestandards intoconformance with thelatest versions of theReliability StandardsDevelopment Procedure,ERO Sanctions Guidelinesand Uniform ComplianceMonitoring andEnforcement Program.

Joe Gardner (MISO) The team is ready to postfor 45-day comment.Resource contraints havedelayed posting ofdocuments due to SPMloading. Resourceconflicts with otherprojects of higher priorityhave impacted schedule.

Posting 1 took longerthan anticipated, andpreparation of Posting 2took longer thananticpated. Resourcecontraints have delayedposting of documentsdue to SPM loading.

Resource conflicts withother projects of higherpriority have impactedschedule.

Project is not urgent/highpriority. No deviationsrequested at this time.

The SDT plans to move693 directives related toTOP/RC approval fromINT-006 (where FERCsuggested them) to theIRO and TOP standards.

The SDT has created anew standard inresponse to the FERCdirective related totagging of internal PTPtransmission. It isuncertain how theindustry will respond.

INT-001throughINT-010New INT-011, -012, -013, and-014

Name: Project 2009-02: Real-time Reliability Monitoring and Analysis Capabilities(1)


Establish requirementsfor the functionality,performance, andmaintenance of Real-time Monitoring andAnalysis capabilities forReliability Coordinators,Transmission Operators,Generator Operators,and Balancing Authoritiesfor use by their SystemOperators in support ofreliable Systemoperations

Sam Brattini Kickoff meeting held theweek of October 18th

White paper on conceptsto be submitted 1Q11

1. Stay away fromnaming tools, emphasizecapabilities2. Differentiationbetween certification andstandards

Newinitiative-decisionto bereachedas otwhetherto reviseexistingstandards or writenewstandards

Name: Project 2010-14 Balancing Authority Reliability-based Controls(1)





Between Plan and

Estimate




Standard

s

Involved

Project 2010-14Balancing AuthorityReliability-based Controls

Doug Hils, Duke & LarryAkens, TVA

Project was just startedas a combination of twoprevious projects: Project2007-05 (BACSDT)and2007-18 (RBCSDT)

N/A Sub-groups have beenassigned to startdevelopment of draftstandards.

1. ACE transmissionlimits.2. Continent-widecontingency reservepolicy.3. Field test.

BAL-001throughBAL-011EOP-002-2, R5IRO-005-2, R4, 8,9, and11


Standards Committee High Priority Goals for 2010

1. Results Based Standards. This is a top initiative for 2010. See November 2009 and subsequent Reports to the MRC and Board of Trustees for full description of project work plan, and outline of success factors.

The Board of Trustees handed off responsibility for implementing results-based approach to the Standards Committee in August, 2010

All coordinators, and six drafting teams have been trained and are implementing the results-based process in developing standards. Training for NERC staff (train-the-trainer) took place the first week of June, 2010 and involved some drafting team chairs, all coordinators, and some regional standards managers.

Results-based standards are under development in six ongoing projects:

Project 2007-7 Vegetation Management (served as proof-of-concept)

Project 2008-01 Voltage and Reactive Planning and Control

Project 2009-01 Disturbance and Sabotage Reporting

Project 2009-02 Real-time Reliability Monitoring and Analysis Capabilities

Project 2009-03 Emergency Operations

Project 2010-14 Balancing Authority Reliability-based Control

In addition, a webinar providing an overview of the result-based initiative and criteria was conducted in October for stakeholders who are interested in learning more about this process.

2. New Standards Process Manual. Completion of industry, BOT and FERC approval, as well as Standards Committee development of revised guidance documents for drafting teams and industry education.

The Standard Processes Manual (SPM) was adopted the board on May 12, 2010 and filed for approval with FERC on June 11, 2010. FERC approved the SPM on September 8, 2010, subject to one clarifying modifications, which is now before the Registered Ballot Body for approval.

Ongoing standards projects are being converted to the new SPM processes when they come before the SC for further action.

The following documents may need to be retired or updated so that they don’t conflict with the new manual:

SAR DT Scope

SDT Scope

Drafting Team Guidelines

Roles and Responsibilities Document

Interpretation Process

Attachment 3b Status of High Priority Goals and Action Items


The Process Subcommittee is working on revisions to the Scope Documents to support the revised standard process and on some of the other documents.

3. Execution of the Standards Committee’s New Charter. The Standards Committee must reach consensus on criteria and processes that we will implement for:

Active prioritization and management of project workload in the Reliability Standards Development Plan based on industry, BOT and regulatory priorities, and resource limitations we all face.

The Standards Committee endorsed filter criteria developed by the Process Subcommittee for ranking and prioritization of proposed standards projects for future development. These criteria were used to rank pending projects in the 2011-13 Reliability Standards Development Plan (RSDP).

In addition, during September-November 2010, a small NERC staff/SC task group has been developing prioritization criteria and a triage plan to categorize pending FERC regulatory directives based on their potential impact on reliability and potential for improving existing reliability standards.

At the November 3-4, 2010 MRC and BOT meetings, NERC’s CEO expressed significant reservations that the 2011-13 RSDP did not prioritize among ongoing standards development projects in terms of their importance to reliability and requested prompt action to develop such a prioritization identifying, for example, the top five or six of NERC’s seventeen ongoing top priority projects.

The SC chair concurred with the CEO’s observations and expressed support for a plan that would combine the subject matter expert judgment approach described by the CEO and the NERC SC’s efforts to develop prioritization criteria.

The CEO’s approach will be valuable to ensure that NERC’s and industry resources are rapidly aligned to focus on projects with the most importance to reliability. The SC’s criteria may help ensure that such reprioritizations support long term development goals and efficient use of resources.

Criteria for standards quality and clarity to ensure ambiguous standards are corrected during the development process

The Standards Committee endorsed the use of applicable sections of a quality check sheet for use in conducting a quality review of standards prior to posting them for stakeholder comment. The topics addressed in the check sheet support scrutinizing a standard to ensure it meets the criteria FERC uses to approve a standard and NERC’s characteristics of an Excellent Reliability Standard. The Process Subcommittee is developing a proposal to identify whether the results of a quality review should be submitted to the entire Standards Committee or to a subcommittee.

On July 26, 2010 a training session was conducted for members of the CCC who volunteered to participate as ‘reviewers’ conducting a “quality review” of standards. The participants provided some constructive feedback on the draft ‘check sheet’ and that feedback has been used to modify the check sheet. There were some questions on the check sheet that were phrased such that they might have encouraged the reviewer to

assess the ‘technical’ aspects of the standard, and these have been rephrased. Another session will be conducted in the near future.

A pilot of portions of the Quality Review was conducted in August, using two members of the CCC who completed the Quality Review training. They reviewed the first draft of the Disturbance and Sabotage Reporting standard.

A second Quality Review training session was conducted in September, with a focus on providing training to legal personnel. The ‘template’ for collecting and providing feedback to drafting teams continues to be refined and is proving useful.

New section proposed to ROP to address March 18 2010 Order.

FERC issued an order on September 18, 2010 denying NERC’s request for rehearing of the March 18 Order directing changes to the NERC Rules of Procedure to ensure that that the BOT may take actions to override decisions by drafting teams to not develop a standard responsive to FERC directives and decisions by the ballot pool to not approve a standard that is responsive to FERC directives.

NERC has posted for industry comment through December 2, 2010 alternative changes to the NERC Rules of Procedure that are responsive to the FERC March 18 and September 16 Orders. A compliance filing is due on December 16, 2010.

At its November 4, 2010 meeting the BOT authorized NERC to appeal the March 18 and September 16 Orders.

Tracking development progress (throughput) and quality.

The SC continues to track Project development status (throughput) on a monthly basis. However, measures and milestones to track project quality concerns/deficiencies have yet to be developed. NERC standards staff continues to consult with FERC staff on its concerns with the content of standards under development, with respect to their responsiveness to FERC directives and acceptability based on other criteria established under various FERC orders.

4. Interpretations Process. Develop a more effective, faster and less resource-intensive alternative to formal standards interpretations. Must be based on the input, views and subject-matter expertise of all NERC programs, Regional Entities, NERC committees, provide due process to Registered Entities and be capable of addressing both ambiguities in the standards and compliance issues. Regulatory buy-in is required.

The Standards Committee endorsed a proposal for implementing a process that can be used to address stakeholder questions that ask for clarity on the application of a standard. The proposal was presented to the MRC and BOT in May, 2010.

The SC has deferred action on the Informal Interpretation Process until procedures and processes used for the development of “Compliance Application Notices” have been refined.

Many factors have caused a delay in developing as many CANs as envisioned. The process continues to be refined, but takes longer than originally anticipated as it now requires stakeholder review and has become an iterative rather than a serial process.

5. NERC as a Learning Organization/Enterprise. Create more effective feedback loops back to standards development (both prioritization and standards content) from standing committees and program areas.

In April members of the standards staff met with Jessica Bian of NERC’s Risk Assessment Program to review some concepts for linking standards to reliability indices.

Mark Lauby made a presentation during the July 2010 Standards Committee meeting, and committed to working with David Taylor during the update to the Reliability Standards Development Plan 20111-2013 to identify areas where new or existing metrics may be used to provide the technical justification for need for new/revised requirements.

6. Communication

Hold a workshop that reviews new/revised standards

Allen Mosher held a spring 2010 webinar (developed by the Communications & Planning Subcommittee) with drafting team chairs, vice chairs and coordinators to review the Standards Committee’s goals and desire to assist teams in meeting their goals and priorities.

NERC held a Standards and Compliance Workshop on Oct 5-6 in St. Louis that was attended by over 200 people

The Chair and Vice Chair hosted a meeting with SDT Chairs and Vice Chairs immediately before the October 2010 SC meeting on October 12 from 1-5. SC members and NERC staff participated in the discussion.

Identify activities from standing committees that can feed into standards

The leadership of the SC met with the leadership of the Standing Committees on June 25, 2010 and discussed the process changes in the Standard Processes Manual that impact the Standing Committees. The group agreed that, when the Standards Committee needs the assistance of a technical committee, the informal process of requesting and receiving assistance needs more structure to ensure that all parties understand what is needed, when it is needed, with an opportunity for discussion and commitment from all involved.

The group also agreed to work with David Taylor to review proposals for new standard projects before the next version of the Reliability Standard Development Plan is finalized – the intent is to provide a technical opinion on the need for a study, data collection, or other reference document to support the new or revised standard.

David Taylor formed a task force with representatives from the Standards Committee and Standing Committees that provided input to the projects in the RSDP 2011-2013. Coordination with standing committees will continue in 2011.

Improved relationship with all regulators and “the hill”

Significant improvements in communication between NERC, industry and regulators have been achieved in 2010, at both a CEO/Commissioner level and at staff levels. Many

of the meetings and workshops listed below have addressed policy issues as well as technical considerations that underlay reliability standard development and compliance:

o FERC Commissioners and senior staff now attend quarterly NERC MRC and BOT meetings.

o Trilateral meetings conducted May 13, 2010 and October 6-7 in Winnipeg.

o FERC Technical Conference on Standards July 6, 2010 (John Q. Anderson, Gerry Cauley and Allen Mosher were panelists).

o FERC Technical Conference on Frequency Response September 23, 2010

o FERC Technical Conference on Vegetation Management October 26, 2010

o FERC Technical Conference on Compliance issues will be held on November 18, 2010

o FERC and NERC plan to convene a “reliability summit” in January – February 2011.

Database for standards

Shaun Streeter has been re-assigned to work on the database.

A contractor is working with NERC.

Standards Committee Action Items

Action Item When Assigned

Status as of November 8, 2010

SC Officers/VP & Director:

1. Update the Roles and Responsibilities Document for Feb 2010 Board meeting

Dec 2009 Open – delayed pending resolution of March 18 Order

2. Coordinate modifications from FMWG to align with the compliance registration criteria

Jan 2010 Open – FM glossary changes proposed, posted for comment, draft responses developed – moved to lower level priority in 2011-2013 RSDP.

3. Develop a process that provides stakeholders with answers to standard “application” questions/ could be informal guidance process or support of CAN process

Jan 2010 Ongoing – continue to work with Mike Moon for questions that have widespread application; attempt to use informal guidance process for questions that apply to a limited number of entities.

4. Implement a relational database for the reliability standards

Jan 2010 Ongoing – consultant hired to assist NERC staff

5. Resolve issue of converting lower level facilitating requirements into “guidelines” and translating “capability” requirements to certification process

Jan 2010 Issue raised with FERC staff and within NERC staff – NERC staff is working on a corporate position. Results-based standards support distinguishing between reliability objectives versus administrative requirements to document compliance.

6. Allen – send a letter to managers of the CIP SDT members advising them of our appreciation/the need for continued commitment

Jul 2010 Open

7. Herb - Develop an integrated proposal (for CANs and standard guidance) for an upcoming SC meeting

Jul 2010 Developing a single process does not seem viable.

8. Consider filing for relief from addressing directives that don’t contribute significantly to reliability;

9. Identify directives that can’t be met by end of 2011

Jul 2010 Ongoing. Small task group has developed draft filter criteria to identify the importance to reliability of pending regulatory directives and a process flow chart to assign directives to specific standards projects.

and report to Commission This process may identify a list of lower level directives for which the SC or SDTs may attempt to identify how the intent of specific directives may be met through alternative means.

This plan needs to align with latest version of RSDP which was approved by BOT in November, 2010

10. Consider presenting the concept of implementing VRF tool and Pro Forma VSLs during the FERC tech conf on compliance issues

Jul 2010 Open. SC chair raised the SC’s concerns with the unintended consequences of current NERC and FERC VRF and VSL criteria with the NERC Board and FERC commissioners at the November BOT meeting.

Communications & Planning Subcommittee:

Process Subcommittee:

1. Develop a recommendation for closing the gap between what is in the standard and what is in the RSAWs

Jul 2009 Open – because of NERC staffing realignments, recommend deferring action

2. Consider making modifications to the Drafting Team Guidelines to indicate that drafting teams that encounter differences of opinion with NERC staff and FERC staff and issues relative to meeting directives should bring those differences to the Standards Committee at the next SC meeting – and staff should address differences the same way

Jul 2009 Open – consider whether resolution should be deferred pending outcomes of the discussions between NERC and FERC on the prioritization of reliability standards development and resolution of FERC’s March 18 and September 16, 2010 Rules of Procedures Orders.

3. Consider whether a subcommittee is needed to review the summaries of Quality Reviews

Apr 2010 Open – planned for Oct 2010 SC PS meeting. At its October 2010 meeting, SC considered use of a rotating group of SC members to conduct the review oversight process. The SCPS is scheduled to bring a proposal to the SC in January 2011.

4. Develop a recommendation - Should the SC adopt an approval process for SARs – are all the technical details identified before the SAR is finalized

Jul 2010 Open

5. Develop a VSL/VRF Flow chart for process development – can SC reject what doesn’t align with

Jul 2010 Open. SC discussed this issue with respect to the ATC VRFs at its October 2010 meeting and confirmed that until modified, the criteria bind NERC staff. The SC chair raised the SC’s concerns with the

Discussion Items for Future SC Meetings: Consider adding to the SC’s “toolbox” the use of ERO’s data request authority under the Rules of Procedure Section 1600

Completed Activities:

guidelines? unintended consequences of current NERC and FERC VRF and VSL criteria with the NERC Board and FERC commissioners at the November BOT meeting.

NERC Staff

1.

VRF Team

1. Develop a 1-page and a 5-page overview of the VRF tool with benefits – must explain how this helps focus on requirements that have greatest impact on reliability

Jul 2010 Open

SC Officers/VP & Director:

Conduct a webinar to inform drafting teams of the SC’s intent to change priorities, potentially defer some projects, and advance other projects; explain need to report deviations/problems to the SC within a month of identification

Apr 2010 Completed May 7, 2010

Hold a conference with FERC staff to prioritize work with the Commission

Feb 2010 Conducted May 26, 2010. Prioritization among current ongoing standards projects is likely to be a central topic at the FERC reliability summit to be held in January or February 2011.

Communications & Planning Subcommittee:

Develop an action plan to inform SDTs about a change in direction

Apr 2010 Submitted for May 2010 SC meeting

Process Subcommittee:

Process Subcommittee and Ad Hoc team to coordinate efforts develop an implementation plan for results-based standards and identify what will be used to judge standards in the future. – copy SC on piece for the SDT; status in Feb; draft in Feb for SC review; full plan for March

Apr 2010 Transition plan submitted to BOT in August, 2010

Consideration of stakeholder comments:

Is an SDT required to provide a response in the same detail as the associated comment?

If comments are submitted during a recirculation ballot, what is the obligation to address these comments?

For similar comments, what is the drafting team’s obligation to provide a “unique” response to each comment or to what extent is it acceptable to group identical/nearly identical comments, and provide a single response?

Sep 2009 Resolved – June 16, 2010 SC PS Subcommittee Meeting:

Drafting teams do need to be responsive to stakeholder comments but drafting teams are not required to respond in the same level of detail as the comment provided.

When a drafting team does not adopt a proposal the team should provide a reason why the proposal was not adopted.

An independent third party review is currently conducted to verify that there is a response to each comment, and this practice should continue.

A commenter who isn’t satisfied with a response can bring an objection to the SDT, the standards staff, the Standards Committee, or could file an appeal.

NERC Staff

Revise the monthly interpretation report to show new interpretation requests

Apr 2010 Done

Update delivery dates on Top Ten Projects Apr 2010 Done

Add a link from a reliability standard to the associated Compliance Application Notice

Jul 2010 Completed August 2, 2010

Develop a proposed set of changes for the SC Charter with non-voting chair and vice chair

Jul 2010 Completed – included in August 2010 agenda package

Set up October SC meeting in Houston – meet with DT leadership afternoon of Oct 12; SC meeting full day Oct 13, until 3 pm Oct 14

Provide hotel info ASAP

Jul 2010 Completed

Need to have concise identification of the objective for each standard – add to SAR form

Jul 2010 Completed – will present to SC in October, 2010

FAC-003-2 — Transmission Vegetation Management

Draft 5: July 305c6: November 29, 2010 1

SSttaannddaarrdd DDeevveellooppmmeenntt TTiimmeelliinnee

This section is maintained by the drafting team during the development of the standard and will be removed when the standard becomes effective. Development Steps Completed

1. SC approved SAR for initial posting (January 11, 2007).

2. SAR posted for comment (January 15–February 14, 2007).

3. SAR posted for comment (April 10–May 9, 2007).

4. SC authorized moving the SAR forward to standard development (June 27, 2007).

Proposed Action Plan and Description of Current Draft This is the third posting of the proposed revisions to the standard in accordance with Results-Based Criteria and the fifth draft overall. Future Development Plan

Anticipated Actions Anticipated Date

Drafting team considers comments, makes conforming changes, and requests SC approval to proceed to formal comment and ballot.

November 2010

Recirculation ballot of standards. November 2010January 2011

Receive BOT approval December 2010February 2011

Attachment 4ai FAC-003 Showing Redline to Quality Review




EEffffeeccttiivvee DDaatteess First calendar day of the first calendar quarter one year after the date of the order approving the standard from applicable regulatory authorities where such explicit approval is required.

Exceptions:

A line operated below 200kV, designated by the Planning Coordinator as an element of an IROL or as a Major WECC transfer path, becomes subject to this standard 12 months after the date the Planning Coordinator or WECC initially designates the line as being subject to this standard.

An existing transmission line operated at 200kV or higher that is newly acquired by an asset owner and was not previously subject to this standard, becomes subject to this standard 12 months after the acquisition date of the line.



VVeerrssiioonn HHiissttoorryy Version Date Action Change Tracking

1 TBA 1. Added “Standard Development Roadmap.”

2. Changed “60” to “Sixty” in section A, 5.2.

3. Added “Proposed Effective Date: April 7, 2006” to footer.

4. Added “Draft 3: November 17, 2005” to footer.

01/20/06

1 April 4, 2007 Regulatory Approval — Effective Date New 2


Draft 5c4: October 85c6: November 29, 2010 4

DDeeffiinniittiioonnss ooff TTeerrmmss UUsseedd iinn SSttaannddaarrdd

This section includes all newly defined or revised terms used in the proposed standard. Terms already defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions listed below become approved when the proposed standard is approved. When the standard becomes effective, these defined terms will be removed from the individual standard and added to the Glossary. When this standard has received ballot approval, the text boxes will be moved to the Guideline and Technical Basis Section.

Right-of-Way (ROW) The corridor of land under a transmission line(s) needed to operate the line(s). The width of the corridor is established by engineering or construction standards as documented in either construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in effect when the line was built. The ROW width in no case exceeds the Transmission Owner’s legal rights but may be less based on the aforementioned criteria. Vegetation Inspection The systematic examination of vegetation conditions on a Right-of-Way and those vegetation conditions under the Transmission Owner’s control that are likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This may be combined with a general line inspection.

The current glossary definition of this NERC term is modified to allow both maintenance inspections and vegetation inspections to be performed concurrently.

Current definition of Vegetation Inspection: The systematic examination of a transmission corridor to document vegetation conditions.

The current glossary definition of this NERC term is modified to address the issues set forth in Paragraph 734 of FERC Order 693.



Introduction

1. Title: Transmission Vegetation Management 2. Number: FAC-003-2 3. Objectives: To improve the reliability of the maintain a reliable electric transmission

system by using a defense-in-depth strategy to manage vegetation located on transmission rights of way (ROW) and minimize encroachments from vegetation located adjacent to the ROW, thus preventing the risk of those vegetation-related outages that could lead to Cascading.

4. Applicability

4.1. Functional Entities:

Transmission Owners

4.2. Facilities: Defined below (referred to as “applicable lines”), including but not limited to those that cross lands owned by federal1, state, provincial, public, private, or tribal entities:

4.2.1. Overhead transmission lines operated at 200kV or higher.

4.2.2. Overhead transmission lines operated below 200kV having been identified as included in the definition of an Interconnection Reliability Operating Limit (IROL) under NERC Standard FAC-014 by the Planning Coordinator.

4.2.3. Overhead transmission lines operated below 200 kV having been identified as included in the definition of one of the Major WECC Transfer Paths in the Bulk Electric System.

4.2.4. This standard does not applyapplies to Facilitiesoverhead transmission lines identified above (4.2.1 through 4.2.3) located inoutside the fenced area of athe switchyard, station or substation and any portion of the span of the transmission line that is crossing the substation fence.

1 EPAct 2005 section 1211c: “Access approvals by Federal agencies”.

Rationale -The areas excluded in 4.2.4 were excluded based on comments from industry for reasons summarized as follows: 1) There is a very low risk from vegetation in this area. Based on an informal survey, no TOs reported such an event. 2) Substations, switchyards, and stations have many inspection and maintenance activities that are necessary for reliability. Those existing process manage the threat. As such, the formal steps in this standard are not well suited for this environment. 3) The standard was written for Transmission Owners. Rolling the excluded areas into this standard will bring GO and DP into the standard, even though NERC has an initiative in place to address this bigger registry issue. 4) Specifically addressing the areas where the standard applies or doesn’t make the standard stronger as it related to clarity.



4.3. Enforcement: The reliability obligations of the applicable entities and facilities are contained within the technical requirements of this standard. [Straw proposal]

5. Background:

This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth approach to improve the reliability of the electric Transmission System by preventing those vegetation related outages that could lead to Cascading. This Standard is not intended to address non-preventable outages such as those due to vegetation fall-ins or blow-ins from outside the Right-of-Way, vandalism, human activities and acts of nature. Operating experience indicates that trees that have grown out of specification have contributed to Cascading, especially under heavy electrical loading conditions.

With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide layers of protection to prevent vegetation related outages that could lead to Cascading:

a) Performance-based — defines a particular reliability objective or outcome to be achieved.

b) Risk-based — preventive requirements to reduce the risks of failure to acceptable tolerance levels.

c) Competency-based — defines a minimum capability an entity needs to have to demonstrate it is able to perform its designated reliability functions.

The defense-in-depth strategy for reliability standards development recognizes that each requirement in a NERC reliability standard has a role in preventing system failures, and that these roles are complementary and reinforcing. Reliability standards should not be viewed as a body of unrelated requirements, but rather should be viewed as part of a portfolio of requirements designed to achieve an overall defense-in-depth strategy and comport with the quality objectives of a reliability standard. For this Standard, the requirements have been developed as follows:

• Performance-based: Requirements 1 and 2

• Competency-based: Requirement 3

• Risk-based: Requirements 4, 5, 6 and 7

Thus the various requirements associated with a successful vegetation program could be viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or final level of defense. R6 depending on the particular vegetation approach may be either an initial defense barrier or a final defense barrier.

Major outages and operational problems have resulted from interference between overgrown vegetation and transmission lines located on many types of lands and ownership situations. Adherence to the Standard requirements for applicable lines on any kind of land or easement,



whether they are Federal Lands, state or provincial lands, public or private lands, franchises, easements or lands owned in fee, will reduce and manage this risk. For the purpose of the Standard the term “public lands” includes municipal lands, village lands, city lands, and a host of other governmental entities.

This Standard addresses vegetation management along applicable overhead lines and does not apply to underground lines, submarine lines or to line sections inside an electric station boundary.

This Standard focuses on transmission lines to prevent those vegetation related outages that could lead to Cascading. It is not intended to prevent customer outages due to tree contact with lower voltage distribution system lines. For example, localized customer service might be disrupted if vegetation were to make contact with a 69kV transmission line supplying power to a 12kV distribution station. However, this Standard is not written to address such isolated situations which have little impact on the overall electric transmission system.

Since vegetation growth is constant and always present, unmanaged vegetation poses an increased outage risk, especially when numerous transmission lines are operating at or near their Rating. This can present a significant risk of multiple line failures and Cascading. Conversely, most other outage causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically intermittent. These events are not any more likely to occur during heavy system loads than any other time. There is no cause-effect relationship which creates the probability of simultaneous occurrence of other such events. Therefore these types of events are highly unlikely to cause large-scale grid failures. Thus, this Standard’s emphasis is on vegetation grow-ins.



Requirements and Measures

R1. Each Transmission Owner shall manage

vegetation to prevent encroachmentencroachments of the types shown below, into the Minimum Vegetation Clearance Distance (MVCD) of any of its applicable line(s) identified as an element of an Interconnection Reliability Operating Limit (IROL) in the planning horizon by the Planning Coordinator; or Major Western Electricity Coordinating Council (WECC) transfer path ((s); operating within its Rating and all Rated Electrical Operating Conditions)2. The four types of failure to manage vegetation, in order of increasing severity, include:3. 1. An encroachment into the Minimum

Vegetation Clearance Distance (MVCD) as shown in FAC-003-Table 2, observed in Real-time, absent a Sustained Outage,

2. An encroachment due to a fall-in from inside the Right-of-Way (ROW) that caused a vegetation-related Sustained Outage,

3. An encroachment due to blowing together of applicable lines and vegetation located inside the ROW that caused a vegetation-related Sustained Outage,

4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage. [VRF – High] [Time Horizon – Real-time]

M1. Each Transmission Owner has evidence that it managed vegetation to prevent

encroachment into the MVCD as described in R1. Examples of acceptable forms of evidence may include dated attestations, dated reports containing no Sustained Outages associated with encroachment types 2 through 4 above, or records confirming no Real-time observations of any MVCD encroachments.

2 This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW. 3 This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.

Rationale The MVCD is a calculated minimum distance stated in feet (meters) to prevent flash-over between conductors and vegetation, for various altitudes and operating voltages. The distances in Table 2 were derived using a proven transmission design method. The types of failure to manage vegetation are listed in order of increasing degrees of severity in non-compliant performance as it relates to a failure of a TO’s vegetation maintenance program. since the encroachments listed require different and increasing levels of skills and knowledge and thus constitute a logical progression of how well, or poorly, a TO manages vegetation relative to this Requirement.



If a later confirmation of a Fault by the Transmission Owner shows that a vegetation encroachment within the MVCD has occurred from vegetation within the ROW, this shall be considered the equivalent of a Real-time observation.

Multiple Sustained Outages on an individual line, if caused by the same vegetation, will be reported as one outage regardless of the actual number of outages within a 24-hour period. (R1)


vegetation to prevent encroachmentencroachments of the types shown below, into the MVCD of any of its applicable line(s) that is not an element of an Interconnection Reliability Operating Limit (IROL); or Major Western Electricity Coordinating Council (WECC) transfer path (; operating within its Rating and all Rated Electrical Operating Conditions)2. The four types of failure to manage vegetation, in order of increasing severity, include: 1. An encroachment into the Minimum

Vegetation Clearance Distance (MVCD) MVCD as shown in FAC-003-Table 2, observed in Real-time, absent a Sustained Outage,

2. An encroachment due to a fall-in from inside the ROW that caused a vegetation-related Sustained Outage,


4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage. [VRF – Medium] [Time Horizon – Real-time]





Rationale The MVCD is a calculated minimum distance stated in feet (meters) to prevent flash-over between conductors and vegetation, for various altitudes and operating voltages. The distances in Table 2 were derived using a proven transmission design method. The types of failure to manage vegetation are listed in order of increasing degrees of severity in non-compliant performance as it relates to a failure of a TO’s vegetation maintenance program. since the encroachments listed require different and increasing levels of skills and knowledge and thus constitute a logical progression of how well, or poorly, a TO manages vegetation relative to this Requirement.



R3. Each Transmission Owner shall

documenthave documented maintenance strategies or procedures or processes or specifications it uses to prevent the encroachment of vegetation into the MVCD. Such documentation will account of its applicable transmission lines that includes the following: 3.1 Accounts for the movement of

applicable transmission line conductors under their Facility Rating and all Rated Electrical Operating Conditions; and

3.2 Accounts for the inter-relationships between vegetation growth rates, vegetation control methods, and inspection frequency, for the Transmission Owner’s applicable lines..

[VRF – Lower] [Time Horizon – Long Term Planning] M3. The maintenance strategies or procedures or processes or specifications provided

demonstrate that the Transmission Owner can prevent encroachment into the MVCD considering the factors identified in the requirement. (R3)

R4. Each Transmission Owner, without any

intentional time delay, shall notify the control center holding switching authority for the associated applicable transmission line when the Transmission Owner has confirmed the existence of a vegetation condition that is likely to cause a Fault at any moment.

[VRF – Medium] [Time Horizon – Real-time] M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a

Fault at any moment will have evidence that it notified the control center holding switching authority for the associated transmission line without any intentional time delay. Examples of evidence may include control center logs, voice recordings, switching orders, clearance orders and subsequent work orders. (R4)

Rationale The documentation provides a basis for evaluating the competency of the Transmission Owner’s vegetation program. There may be many acceptable approaches to maintain clearances. Any approach must demonstrate that the Transmission Owner avoids vegetation-to-wire conflicts under all Rated Electrical Operating Conditions. See Figure 1 for an illustration of possible conductor locations.

Rationale To ensure expeditious communication between the Transmission Owner and the control center when a critical situation is confirmed.



R5. When a Transmission Owner is constrained from performing vegetation work, and the constraint may lead to a vegetation encroachment into the MVCD of its applicable transmission lines prior to the implementation of the next annual work plan then the Transmission Owner shall take corrective action to ensure continued vegetation management to prevent encroachments. [VRF – Medium] [Time Horizon – Operations Planning] M5. Each Transmission Owner has evidence

of the corrective action taken for each constraint where aan applicable transmission line was put at potential risk. Examples of acceptable forms of evidence may include initially-planned work orders, documentation of constraints from landowners, court orders, inspection records of increased monitoring, documentation of the de-rating of lines, revised work orders, invoices, and evidence that a line was de-energized. (R5)

R6. Each Transmission Owner shall perform a

Vegetation Inspection of the entire ROW for all100% of its applicable transmission lines (measured in units of choice - circuit, pole line, line miles or kilometers, etc.) at least once per calendar year butand with no more than 18 months between inspections on the same ROW.4

[VRF – Medium] [Time Horizon – Operations Planning] M6. Each Transmission Owner has evidence

that it conducted Vegetation Inspections of the transmission line ROW for all applicable transmission lines at least once per calendar year but with no more than 18 months between inspections on

4 When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was prevented from performing the Vegetation Inspection.

Rationale Legal actions and other events may occur which result in constraints that prevent the Transmission Owner from performing planned vegetation maintenance work. In cases where the transmission line is put at potential risk due to constraints, the intent is for the Transmission Owner to put interim measures in place, rather than do nothing. The corrective action process is not intended to address situations where a planned work methodology cannot be performed but an alternate work methodology can be used.

Rationale Inspections are used by Transmission Owners to assess the condition of the entire ROW. The information from the assessment can be used to determine risk, determine future work and evaluate recently-completed work. This requirement sets a minimum Vegetation Inspection frequency of once per calendar year but with no more than 18 months between inspections on the same ROW. Based upon average growth rates across North America and on common utility practice, this minimum frequency is reasonable. Transmission Owners should consider local and environmental factors that could warrant more frequent inspections.



the same ROW. Examples of acceptable forms of evidence may include completed and dated work orders, dated invoices, or dated inspection records. (R6)

R7. Each Transmission Owner shall complete the

work in an100% of its annual vegetation work plan to ensure no vegetation encroachments occur within the MVCD. Modifications to the work plan in response to changing conditions or to findings from vegetation inspections may be made and documented (provided they do not put the transmission system at risk of a vegetation encroachment.) and must be documented. The percent completed calculation is based on the number of units actually completed divided by the number of units in the final amended plan (measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples of reasons for modification to annual plan may include:

Change in expected growth rate/ environmental factors Circumstances that are beyond the control of a Transmission Owner5 Rescheduling work between growing seasons Crew or contractor availability/ Mutual assistance agreements Identified unanticipated high priority work Weather conditions/Accessibility Permitting delays Land ownership changes/Change in land use by the landowner Funding adjustments (increase or decrease) Emerging technologies

[VRF – Medium] [Time Horizon – Operations Planning]

M7. Each Transmission Owner has evidence that it completed its annual vegetation work plan. Examples of acceptable forms of evidence may include a copy of the completed annual work plan (including modifications if any), dated work orders, dated invoices, or dated inspection records. The percent completed calculation in the R7 VSLs is based on the number of units actually completed divided by the number of units in the final amended plan.(R7)

5 circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, major storms as defined either by the TO or an applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.

Rationale This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. An annual vegetation work plan allows for work to be modified for changing conditions, taking into consideration anticipated growth of vegetation and all other environmental factors, provided that the changes do not violate the encroachment within the MVCD.



CCoommpplliiaannccee

Compliance Enforcement Authority

Regional Entity

Compliance Monitoring and Enforcement Processes:

Compliance Audits Self-Certifications Spot Checking Compliance Violation Investigations Self-Reporting Complaints Periodic Data Submittals

Evidence Retention

The Transmission Owner retains data or evidence ofto show compliance with Requirements R1 through, R2, R3, R5, R6 and R7, Measures M1 through, M2, M3, M5, M6 and M7 for three calendar years to show compliance unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

The Transmission Owner retains data or evidence to show compliance with Requirement R4, Measure M4 for most recent 12 months of operator logs or most recent 3 months of voice recordings or transcripts of voice recordings, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

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

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

Additional Compliance Information

Periodic Data Submittal: The Transmission Owner will submit a quarterly report to its Regional Entity, or the Regional Entity’s designee, identifying all Sustained Outages of applicable transmission lines determined by the Transmission Owner to have been caused by vegetation, except as excluded in footnote 2, which includes as a minimum, the following:

o The name of the circuit(s), the date, time and duration of the outage; the voltage of the circuit; a description of the cause of the outage; the category associated with the Sustained Outage; other pertinent comments; and any countermeasures taken by the Transmission Owner.

A Sustained Outage is to be categorized as one of the following:

o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into applicable transmission lines, that are identified as an element of an IROL or Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;



o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into applicable transmission lines, but are not identified as an element of an IROL or Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;

o Category 2A — Fall-ins: Sustained Outages caused by vegetation falling into applicable transmission lines that are identified as an element of an IROL or Major WECC Transfer Path, from within the ROW;

o Category 2B — Fall-ins: Sustained Outages caused by vegetation falling into applicable transmission lines, but are not identified as an element of an IROL or Major WECC Transfer Path, from within the ROW;

o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling into applicable transmission lines from outside the ROW;

o Category 4A — Blowing together: Sustained Outages caused by vegetation and applicable transmission lines that are identified as an element of an IROL or Major WECC Transfer Path, blowing together from within the ROW.

o Category 4B — Blowing together: Sustained Outages caused by vegetation and applicable transmission lines, but are not identified as an element of an IROL or Major WECC Transfer Path, blowing together from within the ROW.

The Regional Entity will report the outage information provided by Transmission Owners, as per the above, quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of the reported Sustained Outages.



Time Horizons, Violation Risk Factors, and Violation Severity Levels

Table 1

R# Time Horizon

VRF Violation Severity Level

Lower Moderate High Severe

R1 Real-time High

The Transmission Owner had an encroachment into the MVCD observed in Real-time, absent a Sustained Outage.

The Transmission Owner had an encroachment into the MVCD due to a fall-in from inside the ROW that caused a vegetation-related Sustained Outage.

The Transmission Owner had an encroachment into the MVCD due to blowing together of applicable lines and vegetation located inside the ROW that caused a vegetation-related Sustained Outage.

The Transmission Owner had an encroachment into the MVCD due to a grow-in that caused a vegetation-related Sustained Outage.

R2 Real-time Medium





R3 Long-Term Planning Lower

The Transmission Owner has maintenance strategies or documented procedures or processes or specifications but has not accounted for the inter-relationships between

The Transmission Owner has maintenance strategies or documented procedures or processes or specifications but has not accounted for the

The Transmission Owner does not have any maintenance strategies or documented procedures or processes or specifications used to prevent the



vegetation growth rates, vegetation control methods, and inspection frequency, for the Transmission Owner’s applicable lines.

movement of transmission line conductors under their Rating and all Rated Electrical Operating Conditions, for the Transmission Owner’s applicable lines.

encroachment of vegetation into the MVCD, for the Transmission Owner’s applicable lines.

R4 Real-time Medium

The Transmission Owner experienced a confirmed vegetation threat and notified the control center holding switching authority for that transmission line, but there was intentional delay in that notification.

The Transmission Owner experienced a confirmed vegetation threat and did not notify the control center holding switching authority for that transmission line.

R5 Operations Planning Medium

The Transmission Owner did not take corrective action when it was constrained from performing planned vegetation work where a transmission line was put at potential risk.


The Transmission Owner failed to inspect 5% or less of the ROW as measured byits applicable-line miles (kilometers) (based on transmission lines

The Transmission Owner failed to inspect more than 5% up to and including 10% of the ROW as measured byits applicable-line miles (kilometers) (based on transmission lines (measured in units of choice: - circuit, pole line, ROWline miles or kilometers, etc.).

The Transmission Owner failed to inspect more than 10% up to and including 15% of the ROW as measured byits applicable-line miles (kilometers) (based on transmission lines (measured in units of choice: - circuit, pole line, ROWline miles or kilometers, etc.).

The Transmission Owner failed to inspect more than 15% of the ROW as measured byits applicable-line miles (kilometers) (based on transmission lines (measured in units of choice: - circuit, pole line, ROWline miles or kilometers, etc.).

Formatted Table



(measured in units of choice: - circuit, pole line, ROWline miles or kilometers, etc.)..)


The Transmission Owner failed to complete up to 5% of its annual vegetation work plan (including modifications if any).

The Transmission Owner failed to complete more than 5% and up to 10% of its annual vegetation work plan (including modifications if any).


The Transmission Owner failed to complete more than 15% of its annual vegetation work plan (including modifications if any).



VVaarriiaanncceess

None. IInntteerrpprreettaattiioonnss

None.



GGuuiiddeelliinnee aanndd TTeecchhnniiccaall BBaassiiss Requirements R1 and R2: R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the prevention of vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation to prevent encroachment within the Minimum Vegetation Clearance Distance (“MVCD”) of transmission lines. R1 is applicable to lines “identified as an element of an Interconnection Reliability Operating Limit (IROL) or Major Western Electricity Coordinating Council (WECC) transfer path (operating within Rating and Rated Electrical Operating Conditions) to avoid a Sustained Outage”. R2 applies to all other applicable lines that are not an element of an IROL or Major WECC Transfer Path.

The separation of applicability (between R1 and R2) recognizes that an encroachment into the MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the electric transmission system. Applicable lines that are not an element of an IROL or Major WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less operationally significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for R2.

These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table 1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-003-2 Technical Reference document, it is in violation of the standard. Table 2 tabulates the distances necessary to prevent spark-over based on the Gallet equations as described more fully in Appendix 1 below.

These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating (potentially in violation of other standards), the occurrence of a clearance encroachment may occur. For example, emergency actions taken by a Transmission Operator or Reliability Coordinator to protect an Interconnection may cause the transmission line to sag more and come closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a violation of these requirements.

Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to blowing together of applicable lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. If an investigation of a Fault by a Transmission Owner confirms that a vegetation encroachment within the MVCD occurred, then it shall be considered the equivalent of a Real-time observation.

With this approach, the VSLs were defined such that they directly correlate to the severity of a failure of a Transmission Owner to manage vegetation and to the corresponding performance level of the Transmission Owner’s vegetation program’s ability to meet the goal of “preventing a Sustained Outage that could lead to Cascading.” Thus violation severity increases with a Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading



event. The additional benefits of such a combination are that it simplifies the standard and clearly defines performance for compliance. A performance-based requirement of this nature will promote high quality, cost effective vegetation management programs that will deliver the overall end result of improved reliability to the system.

Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example, a limb may only partially break and intermittently contact a conductor. Such events are considered to be a single vegetation-related Sustained Outage under the Standard where the Sustained Outages occur within a 24 hour period.

The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission outages. Requirement R3: Requirement R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or specifications, a Transmission Owner uses for vegetation management.

An adequate transmission vegetation management program formally establishes the approach the Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained Outages and minimize risk to the Transmission System. The approach provides the basis for evaluating the intent, allocation of appropriate resources and the competency of the Transmission Owner in managing vegetation. There are many acceptable approaches to manage vegetation and avoid Sustained Outages. However, the Transmission Owner must be able to state what its approach is and how it conducts work to maintain clearances.

An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a utility uses to manage vegetation, any approach a Transmission Owner chooses to use will generally contain the following elements:

1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to ensure that MVCD clearances are never violated.

2. the work methods that the Transmission Owner uses to control vegetation

3. a stated Vegetation Inspection frequency

4. an annual work plan The conductor’s position in space at any point in time is continuously changing as a reaction to a number of different loading variables. Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is illustrated in Figure 1 below.



Figure 1 Cross-section view of a single conductor at a given point along the span showing six possible conductor positions due to movement resulting from thermal and mechanical loading.

Requirement R4: R4 is a risk-based requirement. It focuses on preventative actions to be taken by the Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation conditions, without any intentional delay, to the control center holding switching authority for that specific transmission line. Examples of acceptable unintentional delays may include communication system problems (for example, cellular service or two-way radio disabled), crews located in remote field locations with no communication access, delays due to severe weather, etc. Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of a Transmission Owner’s employee who personally identifies such a threat in the field. Confirmation could also be made by sending out an employee to evaluate a situation reported by a landowner.



Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating. The Transmission Owner has the responsibility to ensure the proper communication between field personnel and the control center to allow the control center to take the appropriate action until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of service, or positioning the system in recognition of the increasing risk of outage on that circuit. The notification of the threat should be communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5). All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some Transmission Owners may have a danger tree identification program that identifies trees for removal with the potential to fall near the line. These trees would not require notification to the control center unless they pose an immediate fall-in threat. Requirement R5: R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing vegetation maintenance. The intent of this requirement is to deal with situations that prevent the Transmission Owner from performing planned vegetation management work and, as a result, have the potential to put the transmission line at risk. Constraints to performing vegetation maintenance work as planned could result from legal injunctions filed by property owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or other circumstances. This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the Transmission Owner is not under any immediate time constraint for achieving the management objective, can easily reschedule work using an alternate approach, and therefore does not need to take interim corrective action. However, in situations where transmission line reliability is potentially at risk due to a constraint, the Transmission Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line. A wide range of actions can be taken to address various situations. General considerations include:

Identifying locations where the Transmission Owner is constrained from performing planned vegetation maintenance work which potentially leaves the transmission line at risk.

Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance work as planned.



Documenting and tracking the specific action taken for each location.

In developing the specific action to mitigate the potential risk to the transmission line the Transmission Owner could consider location specific measures such as modifying the inspection and/or maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim corrective action could include limiting the loading on the transmission line.

The Transmission Owner should document and track the specific corrective action taken at each location. This location may be indicated as one span, one tree or a combination of spans on one property where the constraint is considered to be temporary.

Requirement R6: R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation Inspections can be performed in conjunction with general line inspections further facilitates a Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may determine that more frequent inspections are needed to maintain reliability levels, dependent upon such factors as anticipated growth rates of the local vegetation, length of the growing season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is expected that some transmission lines may be designated with a higher frequency of inspections. The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW inspections completed. To calculate the percentage of inspection completion, the Transmission Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line miles, ROW miles, etc. For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission lines at least once during the calendar year. If one of the included lines was 100 miles long, and if it was not inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this example. Requirement R7: R7 is a risk-based requirement. The Transmission Owner is required to implement an annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work plan in response to changing conditions or to findings from vegetation inspections may be made and documented provided they do not put the transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to be performed. It is only intended to require that the Transmission Owner provide evidence of annual planning and execution of a vegetation management maintenance approach which successfully prevents encroachment of vegetation into the MVCD.



The ability to modify the work plan allows the Transmission Owner to change priorities or treatment methodologies during the year as conditions or situations dictate. For example recent line inspections may identify unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the plan year, or a major storm could require redirecting local resources away from planned maintenance. This situation may also include complying with mutual assistance agreements by moving resources off the Transmission Owner’s system to work on another system. Any of these examples could result in acceptable deferrals or additions to the annual work plan. Modifications to the annual work plan must always ensure the reliability of the electric Transmission system. In general, the vegetation management maintenance approach should use the full extent of the Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach that exercises the full extent of legal rights on the ROW is superior to incremental management in the long term because it reduces the overall potential for encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient. When developing the annual work plan the Transmission Owner should allow time for procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Transmission Owners may also need to consider those special landowner requirements as documented in easement instruments. This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by the Transmission Owner, evidence of successful annual work plan execution could consist of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of planned versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and walk-through reports.


Draft 5c4: September 305c6: November 29, 2010 25

FFAACC--000033 —— TTAABBLLEE 22 —— MMiinniimmuumm VVeeggeettaattiioonn CClleeaarraannccee DDiissttaanncceess ((MMVVCCDD))66 For Alternating Current Voltages

( AC ) Nominal System Voltage (kV)

( AC ) Maximum System Voltage (kV)

MVCD feet

(meters)

sea level

MVCD

feet (meters) 3,000ft

(914.4m)

MVCD


(1219.2m)

MVCD


(1524m)

MVCD


(1828.8m)

MVCD


(2133.6m)

MVCD


(2438.4m)

MVCD


(2743.2m)

MVCD

feet (meters) 10,000ft (3048m)

MVCD


(3352.8m)

765 800 8.06ft

(2.46m) 8.89ft

(2.71m) 9.17ft

(2.80m) 9.45ft

(2.88m) 9.73ft

(2.97m) 10.01ft (3.05m)

10.29ft (3.14m)

10.57ft (3.22m)

10.85ft (3.31m)

11.13ft (3.39m)

500 550 5.06ft

(1.54m) 5.66ft

(1.73m) 5.86ft

(1.79m) 6.07ft

(1.85m) 6.28ft

(1.91m) 6.49ft

(1.98m) 6.7ft

(2.04m) 6.92ft

(2.11m) 7.13ft

(2.17m) 7.35ft

(2.24m)

345 362 3.12ft

(0.95m) 3.53ft

(1.08m) 3.67ft

(1.12m) 3.82ft

(1.16m) 3.97ft

(1.21m) 4.12ft

(1.26m) 4.27ft

(1.30m) 4.43ft

(1.35m) 4.58ft

(1.40m) 4.74ft

(1.44m)

230 242 2.97ft

(0.91m) 3.36ft

(1.02m) 3.49ft

(1.06m) 3.63ft

(1.11m) 3.78ft

(1.15m) 3.92ft

(1.19m) 4.07ft

(1.24m) 4.22ft

(1.29m) 4.37ft

(1.33m) 4.53ft

(1.38m)

161* 169 2ft

(0.61m) 2.28ft

(0.69m) 2.38ft

(0.73m) 2.48ft

(0.76m) 2.58ft

(0.79m) 2.69ft

(0.82m) 2.8ft

(0.85m) 2.91ft

(0.89m) 3.03ft

(0.92m) 3.14ft

(0.96m)

138* 145 1.7ft

(0.52m) 1.94ft

(0.59m) 2.03ft

(0.62m) 2.12ft

(0.65m) 2.21ft

(0.67m) 2.3ft

(0.70m) 2.4ft

(0.73m) 2.49ft

(0.76m) 2.59ft

(0.79m) 2.7ft

(0.82m)

115* 121 1.41ft

(0.43m) 1.61ft

(0.49m) 1.68ft

(0.51m) 1.75ft

(0.53m) 1.83ft

(0.56m) 1.91ft

(0.58m) 1.99ft

(0.61m) 2.07ft

(0.63m) 2.16ft

(0.66m) 2.25ft

(0.69m)

88* 100 1.15ft

(0.35m) 1.32ft

(0.40m) 1.38ft

(0.42m) 1.44ft

(0.44m) 1.5ft

(0.46m) 1.57ft

(0.48m) 1.64ft

(0.50m) 1.71ft

(0.52m) 1.78ft

(0.54m) 1.86ft

(0.57m)

69* 72 0.82ft

(0.25m) 0.94ft

(0.29m) 0.99ft

(0.30m) 1.03ft

(0.31m) 1.08ft

(0.33m) 1.13ft

(0.34m) 1.18ft

(0.36m) 1.23ft

(0.37m) 1.28ft

(0.39m) 1.34ft

(0.41m)

* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).

6 The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be achieved at time of vegetation maintenance.



TTaabbllee 22 ((ccoonntt..)) —— MMiinniimmuumm VVeeggeettaattiioonn CClleeaarraannccee DDiissttaanncceess ((MMVVCCDD)) For Direct Current Voltages

( DC ) Nominal Pole

to Ground Voltage

(kV)

MVCD feet

(meters)

sea level

MVCD feet

(meters) 3,000ft

(914.4m) Alt.

MVCD feet

(meters) 4,000ft

(1219.2m) Alt.

MVCD feet

(meters) 5,000ft

(1524m) Alt.

MVCD feet

(meters) 6,000ft

(1828.8m) Alt.

MVCD feet

(meters) 7,000ft

(2133.6m) Alt.

MVCD feet

(meters) (8,000ft

(2438.4m) Alt.

MVCD feet

(meters) 9,000ft

(2743.2m) Alt.

MVCD feet

(meters) 10,000ft (3048m)

Alt.

MVCD feet

(meters) 11,000ft

(3352.8m) Alt.

±750 13.92ft (4.24m)

15.07ft (4.59m)

15.45ft (4.71m)

15.82ft (4.82m)

16.2ft (4.94m)

16.55ft (5.04m)

16.9ft (5.15m)

17.27ft (5.26m)

17.62ft (5.37m)

17.97ft (5.48m)

±600 10.07ft (3.07m)

11.04ft (3.36m)

11.35ft (3.46m)

11.66ft (3.55m)

11.98ft (3.65m)

12.3ft (3.75m)

12.62ft (3.85m)

12.92ft (3.94m)

13.24ft (4.04m)

(13.54ft 4.13m)

±500 7.89ft

(2.40m) 8.71ft

(2.65m) 8.99ft

(2.74m) 9.25ft

(2.82m) 9.55ft

(2.91m) 9.82ft

(2.99m) 10.1ft

(3.08m) 10.38ft (3.16m)

10.65ft (3.25m)

10.92ft (3.33m)

±400 4.78ft

(1.46m) 5.35ft

(1.63m) 5.55ft

(1.69m) 5.75ft

(1.75m) 5.95ft

(1.81m) 6.15ft

(1.87m) 6.36ft

(1.94m) 6.57ft

(2.00m) 6.77ft

(2.06m) 6.98ft

(2.13m)

±250 3.43ft

(1.05m) 4.02ft

(1.23m) 4.02ft

(1.23m) 4.18ft

(1.27m) 4.34ft

(1.32m) 4.5ft

(1.37m) 4.66ft

(1.42m) 4.83ft

(1.47m) 5ft

(1.52m) 5.17ft

(1.58m)

Notes: The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more appropriate is explained in the paragraphs below. The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic maximum transient over-voltages factors for in-service transmission lines. The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:



avoid the problem associated with referring to tables in another standard (IEEE-516-2003) transmission lines operate in non-laboratory environments (wet conditions) transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines

with trapped charges. FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions. Consequently, the validity of using these distances in an outside environment application has been questioned. FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 5 could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 7 would have to be used. Table 7 represented minimum air insulation distances under the worst possible case for transient over-voltage factors. These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this particular application of the distances. In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that occur only while the line is energized. Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient over-voltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g. closing resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.



Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient over-voltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is considered a realistic maximum. The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap geometries. This approach was used to design the first 500 kV and 765 kV lines in North America [1]. If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the Gallet equations yield a more conservative (larger) minimum distance value. Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516 equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions. While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice. The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations using various transient overvoltage values.



Comparison of spark-over distances computed using Gallet wet equations vs.

IEEE 516-2003 MAID distances using various transient over-voltage factors

Table 5

( AC ) ( AC ) Transient Clearance (ft.) IEEE 516 Nom System Max System Over-voltage Gallet (wet) MAID (ft) Voltage (kV) Voltage (kV) Factor (T) @ Alt. 3000 feet @ Alt. 3000 feet

765 800 1.4 8.89 8.65 500 550 1.4 5.65 4.92 345 362 1.4 3.52 3.13 230 242 2.0 3.35 2.8

115 121 2.0 1.6 1.4

Table 5

(historical maximums) ( AC ) ( AC ) Transient Clearance (ft.) IEEE 516

Nom System Max System Over-voltage Gallet (wet) MAID (ft) Voltage (kV) Voltage (kV) Factor (T) @ Alt. 3000 feet @ Alt. 3000 feet

765 800 2.0 14.36 13.95 500 550 2.4 11.0 10.07 345 362 3.0 8.55 7.47 230 242 3.0 5.28 4.2

115 121 3.0 2.46 2.1



Table 7


765 800 2.5 20.25 20.4 500 550 3.0 15.02 14.7 345 362 3.5 10.42 9.44

230 242 3.5 6.32 5.14

115 121 3.5 2.90 2.45


Draft 5c6: November 29, 2010 1

SSttaannddaarrdd DDeevveellooppmmeenntt TTiimmeelliinnee

This section is maintained by the drafting team during the development of the standard and will be removed when the standard becomes effective. Development Steps Completed

1. SC approved SAR for initial posting (January 11, 2007).

2. SAR posted for comment (January 15–February 14, 2007).

3. SAR posted for comment (April 10–May 9, 2007).

4. SC authorized moving the SAR forward to standard development (June 27, 2007).

Proposed Action Plan and Description of Current Draft This is the third posting of the proposed revisions to the standard in accordance with Results-Based Criteria and the fifth draft overall. Future Development Plan

Anticipated Actions Anticipated Date

Drafting team considers comments, makes conforming changes, and requests SC approval to proceed to formal comment and ballot.

November 2010

Recirculation ballot of standards. January 2011

Receive BOT approval February 2011

Attachment 4aii FAC-003 Clean

Standards Committee December 9, 2010



EEffffeeccttiivvee DDaatteess First calendar day of the first calendar quarter one year after the date of the order approving the standard from applicable regulatory authorities where such explicit approval is required.

Exceptions:

A line operated below 200kV, designated by the Planning Coordinator as an element of an IROL or as a Major WECC transfer path, becomes subject to this standard 12 months after the date the Planning Coordinator or WECC initially designates the line as being subject to this standard.

An existing transmission line operated at 200kV or higher that is newly acquired by an asset owner and was not previously subject to this standard, becomes subject to this standard 12 months after the acquisition date of the line.



VVeerrssiioonn HHiissttoorryy Version Date Action Change Tracking

1 TBA 1. Added “Standard Development Roadmap.”

2. Changed “60” to “Sixty” in section A, 5.2.

3. Added “Proposed Effective Date: April 7, 2006” to footer.

4. Added “Draft 3: November 17, 2005” to footer.

01/20/06

1 April 4, 2007 Regulatory Approval — Effective Date New 2



DDeeffiinniittiioonnss ooff TTeerrmmss UUsseedd iinn SSttaannddaarrdd

This section includes all newly defined or revised terms used in the proposed standard. Terms already defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions listed below become approved when the proposed standard is approved. When the standard becomes effective, these defined terms will be removed from the individual standard and added to the Glossary. When this standard has received ballot approval, the text boxes will be moved to the Guideline and Technical Basis Section.

Right-of-Way (ROW) The corridor of land under a transmission line(s) needed to operate the line(s). The width of the corridor is established by engineering or construction standards as documented in either construction documents, pre-2007 vegetation maintenance records, or by the blowout standard in effect when the line was built. The ROW width in no case exceeds the Transmission Owner’s legal rights but may be less based on the aforementioned criteria. Vegetation Inspection The systematic examination of vegetation conditions on a Right-of-Way and those vegetation conditions under the Transmission Owner’s control that are likely to pose a hazard to the line(s) prior to the next planned maintenance or inspection. This may be combined with a general line inspection.

The current glossary definition of this NERC term is modified to allow both maintenance inspections and vegetation inspections to be performed concurrently.

Current definition of Vegetation Inspection: The systematic examination of a transmission corridor to document vegetation conditions.

The current glossary definition of this NERC term is modified to address the issues set forth in Paragraph 734 of FERC Order 693.



Introduction

1. Title: Transmission Vegetation Management 2. Number: FAC-003-2 3. Objectives: To maintain a reliable electric transmission system by using a defense-in-

depth strategy to manage vegetation located on transmission rights of way (ROW) and minimize encroachments from vegetation located adjacent to the ROW, thus preventing the risk of those vegetation-related outages that could lead to Cascading.

4. Applicability

4.1. Functional Entities:

Transmission Owners

4.2. Facilities: Defined below (referred to as “applicable lines”), including but not limited to those that cross lands owned by federal1, state, provincial, public, private, or tribal entities:

4.2.1. Overhead transmission lines operated at 200kV or higher.

4.2.2. Overhead transmission lines operated below 200kV having been identified as included in the definition of an Interconnection Reliability Operating Limit (IROL) under NERC Standard FAC-014 by the Planning Coordinator.

4.2.3. Overhead transmission lines operated below 200 kV having been identified as included in the definition of one of the Major WECC Transfer Paths in the Bulk Electric System.

4.2.4. This standard applies to overhead transmission lines identified above (4.2.1 through 4.2.3) located outside the fenced area of the switchyard, station or substation and any portion of the span of the transmission line that is crossing the substation fence.

1 EPAct 2005 section 1211c: “Access approvals by Federal agencies”.

Rationale -The areas excluded in 4.2.4 were excluded based on comments from industry for reasons summarized as follows: 1) There is a very low risk from vegetation in this area. Based on an informal survey, no TOs reported such an event. 2) Substations, switchyards, and stations have many inspection and maintenance activities that are necessary for reliability. Those existing process manage the threat. As such, the formal steps in this standard are not well suited for this environment. 3) The standard was written for Transmission Owners. Rolling the excluded areas into this standard will bring GO and DP into the standard, even though NERC has an initiative in place to address this bigger registry issue. 4) Specifically addressing the areas where the standard applies or doesn’t make the standard stronger as it related to clarity.



4.3. Enforcement: The reliability obligations of the applicable entities and facilities are contained within the technical requirements of this standard. [Straw proposal]

5. Background:

This NERC Vegetation Management Standard (“Standard”) uses a defense-in-depth approach to improve the reliability of the electric Transmission System by preventing those vegetation related outages that could lead to Cascading. This Standard is not intended to address non-preventable outages such as those due to vegetation fall-ins or blow-ins from outside the Right-of-Way, vandalism, human activities and acts of nature. Operating experience indicates that trees that have grown out of specification have contributed to Cascading, especially under heavy electrical loading conditions.

With a defense-in-depth strategy, this Standard utilizes three types of requirements to provide layers of protection to prevent vegetation related outages that could lead to Cascading:

a) Performance-based — defines a particular reliability objective or outcome to be achieved.

b) Risk-based — preventive requirements to reduce the risks of failure to acceptable tolerance levels.

c) Competency-based — defines a minimum capability an entity needs to have to demonstrate it is able to perform its designated reliability functions.

The defense-in-depth strategy for reliability standards development recognizes that each requirement in a NERC reliability standard has a role in preventing system failures, and that these roles are complementary and reinforcing. Reliability standards should not be viewed as a body of unrelated requirements, but rather should be viewed as part of a portfolio of requirements designed to achieve an overall defense-in-depth strategy and comport with the quality objectives of a reliability standard. For this Standard, the requirements have been developed as follows:

• Performance-based: Requirements 1 and 2

• Competency-based: Requirement 3

• Risk-based: Requirements 4, 5, 6 and 7

Thus the various requirements associated with a successful vegetation program could be viewed as using R1, R2 and R3 as first levels of defense; while R4 could be a subsequent or final level of defense. R6 depending on the particular vegetation approach may be either an initial defense barrier or a final defense barrier.

Major outages and operational problems have resulted from interference between overgrown vegetation and transmission lines located on many types of lands and ownership situations. Adherence to the Standard requirements for applicable lines on any kind of land or easement,



whether they are Federal Lands, state or provincial lands, public or private lands, franchises, easements or lands owned in fee, will reduce and manage this risk. For the purpose of the Standard the term “public lands” includes municipal lands, village lands, city lands, and a host of other governmental entities.

This Standard addresses vegetation management along applicable overhead lines and does not apply to underground lines, submarine lines or to line sections inside an electric station boundary.

This Standard focuses on transmission lines to prevent those vegetation related outages that could lead to Cascading. It is not intended to prevent customer outages due to tree contact with lower voltage distribution system lines. For example, localized customer service might be disrupted if vegetation were to make contact with a 69kV transmission line supplying power to a 12kV distribution station. However, this Standard is not written to address such isolated situations which have little impact on the overall electric transmission system.

Since vegetation growth is constant and always present, unmanaged vegetation poses an increased outage risk, especially when numerous transmission lines are operating at or near their Rating. This can present a significant risk of multiple line failures and Cascading. Conversely, most other outage causes (such as trees falling into lines, lightning, animals, motor vehicles, etc.) are statistically intermittent. These events are not any more likely to occur during heavy system loads than any other time. There is no cause-effect relationship which creates the probability of simultaneous occurrence of other such events. Therefore these types of events are highly unlikely to cause large-scale grid failures. Thus, this Standard’s emphasis is on vegetation grow-ins.



Requirements and Measures


vegetation to prevent encroachments of the types shown below, into the Minimum Vegetation Clearance Distance (MVCD) of any of its applicable line(s) identified as an element of an Interconnection Reliability Operating Limit (IROL) in the planning horizon by the Planning Coordinator; or Major Western Electricity Coordinating Council (WECC) transfer path(s); operating within its Rating and all Rated Electrical Operating Conditions2. 1. An encroachment into the MVCD as

shown in FAC-003-Table 2, observed in Real-time, absent a Sustained Outage,

2. An encroachment due to a fall-in from inside the Right-of-Way (ROW) that caused a vegetation-related Sustained Outage,


4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage. [VRF – High] [Time Horizon – Real-time]





2 This requirement does not apply to circumstances that are beyond the control of a Transmission Owner subject to this reliability standard, including natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, wind shear, fresh gale, major storms as defined either by the Transmission Owner or an applicable regulatory body, ice storms, and floods; human or animal activity such as logging, animal severing tree, vehicle contact with tree, arboricultural activities or horticultural or agricultural activities, or removal or digging of vegetation. Nothing in this footnote should be construed to limit the Transmission Owner’s right to exercise its full legal rights on the ROW.

Rationale The MVCD is a calculated minimum distance stated in feet (meters) to prevent flash-over between conductors and vegetation, for various altitudes and operating voltages. The distances in Table 2 were derived using a proven transmission design method. The types of failure to manage vegetation are listed in order of increasing degrees of severity in non-compliant performance as it relates to a failure of a TO’s vegetation maintenance program since the encroachments listed require different and increasing levels of skills and knowledge and thus constitute a logical progression of how well, or poorly, a TO manages vegetation relative to this Requirement.




vegetation to prevent encroachments of the types shown below, into the MVCD of any of its applicable line(s) that is not an element of an IROL; or Major WECC transfer path; operating within its Rating and all Rated Electrical Operating Conditions2. 1. An encroachment into the MVCD as

shown in FAC-003-Table 2, observed in Real-time, absent a Sustained Outage,

2. An encroachment due to a fall-in from inside the ROW that caused a vegetation-related Sustained Outage,


4. An encroachment due to a grow-in that caused a vegetation-related Sustained Outage.

[VRF – Medium] [Time Horizon – Real-time]

M2. Each Transmission Owner has evidence that it managed vegetation to prevent encroachment into the MVCD as described in R2. Examples of acceptable forms of evidence may include dated attestations, dated reports containing no Sustained Outages associated with encroachment types 2 through 4 above, or records confirming no Real-time observations of any MVCD encroachments.



Rationale The MVCD is a calculated minimum distance stated in feet (meters) to prevent flash-over between conductors and vegetation, for various altitudes and operating voltages. The distances in Table 2 were derived using a proven transmission design method. The types of failure to manage vegetation are listed in order of increasing degrees of severity in non-compliant performance as it relates to a failure of a TO’s vegetation maintenance program since the encroachments listed require different and increasing levels of skills and knowledge and thus constitute a logical progression of how well, or poorly, a TO manages vegetation relative to this Requirement.



R3. Each Transmission Owner shall have

documented maintenance strategies or procedures or processes or specifications it uses to prevent the encroachment of vegetation into the MVCD of its applicable transmission lines that includes the following: 3.1 Accounts for the movement of

applicable transmission line conductors under their Facility Rating and all Rated Electrical Operating Conditions;

3.2 Accounts for the inter-relationships between vegetation growth rates, vegetation control methods, and inspection frequency.

[VRF – Lower] [Time Horizon – Long Term Planning] M3. The maintenance strategies or procedures or processes or specifications provided

demonstrate that the Transmission Owner can prevent encroachment into the MVCD considering the factors identified in the requirement. (R3)

R4. Each Transmission Owner, without any

intentional time delay, shall notify the control center holding switching authority for the associated applicable transmission line when the Transmission Owner has confirmed the existence of a vegetation condition that is likely to cause a Fault at any moment.

[VRF – Medium] [Time Horizon – Real-time] M4. Each Transmission Owner that has a confirmed vegetation condition likely to cause a

Fault at any moment will have evidence that it notified the control center holding switching authority for the associated transmission line without any intentional time delay. Examples of evidence may include control center logs, voice recordings, switching orders, clearance orders and subsequent work orders. (R4)

Rationale The documentation provides a basis for evaluating the competency of the Transmission Owner’s vegetation program. There may be many acceptable approaches to maintain clearances. Any approach must demonstrate that the Transmission Owner avoids vegetation-to-wire conflicts under all Rated Electrical Operating Conditions. See Figure 1 for an illustration of possible conductor locations.

Rationale To ensure expeditious communication between the Transmission Owner and the control center when a critical situation is confirmed.



R5. When a Transmission Owner is constrained from performing vegetation work, and the constraint may lead to a vegetation encroachment into the MVCD of its applicable transmission lines prior to the implementation of the next annual work plan then the Transmission Owner shall take corrective action to ensure continued vegetation management to prevent encroachments. [VRF – Medium] [Time Horizon – Operations Planning] M5. Each Transmission Owner has evidence

of the corrective action taken for each constraint where an applicable transmission line was put at potential risk. Examples of acceptable forms of evidence may include initially-planned work orders, documentation of constraints from landowners, court orders, inspection records of increased monitoring, documentation of the de-rating of lines, revised work orders, invoices, and evidence that a line was de-energized. (R5)

R6. Each Transmission Owner shall perform a

Vegetation Inspection of 100% of its applicable transmission lines (measured in units of choice - circuit, pole line, line miles or kilometers, etc.) at least once per calendar year and with no more than 18 months between inspections on the same ROW.3

[VRF – Medium] [Time Horizon – Operations Planning] M6. Each Transmission Owner has evidence

that it conducted Vegetation Inspections of the transmission line ROW for all applicable transmission lines at least once per calendar year but with no more than 18 months between inspections on the same ROW. Examples of acceptable

3 When the Transmission Owner is prevented from performing a Vegetation Inspection within the timeframe in R6 due to a natural disaster, the TO is granted a time extension that is equivalent to the duration of the time the TO was prevented from performing the Vegetation Inspection.

Rationale Legal actions and other events may occur which result in constraints that prevent the Transmission Owner from performing planned vegetation maintenance work. In cases where the transmission line is put at potential risk due to constraints, the intent is for the Transmission Owner to put interim measures in place, rather than do nothing. The corrective action process is not intended to address situations where a planned work methodology cannot be performed but an alternate work methodology can be used.

Rationale Inspections are used by Transmission Owners to assess the condition of the entire ROW. The information from the assessment can be used to determine risk, determine future work and evaluate recently-completed work. This requirement sets a minimum Vegetation Inspection frequency of once per calendar year but with no more than 18 months between inspections on the same ROW. Based upon average growth rates across North America and on common utility practice, this minimum frequency is reasonable. Transmission Owners should consider local and environmental factors that could warrant more frequent inspections.



forms of evidence may include completed and dated work orders, dated invoices, or dated inspection records. (R6)

R7. Each Transmission Owner shall complete

100% of its annual vegetation work plan to ensure no vegetation encroachments occur within the MVCD. Modifications to the work plan in response to changing conditions or to findings from vegetation inspections may be made (provided they do not put the transmission system at risk of a vegetation encroachment) and must be documented. The percent completed calculation is based on the number of units actually completed divided by the number of units in the final amended plan (measured in units of choice - circuit, pole line, line miles or kilometers, etc.) Examples of reasons for modification to annual plan may include:

Change in expected growth rate/ environmental factors Circumstances that are beyond the control of a Transmission Owner4 Rescheduling work between growing seasons Crew or contractor availability/ Mutual assistance agreements Identified unanticipated high priority work Weather conditions/Accessibility Permitting delays Land ownership changes/Change in land use by the landowner Emerging technologies

[VRF – Medium] [Time Horizon – Operations Planning]

M7. Each Transmission Owner has evidence that it completed its annual vegetation work plan. Examples of acceptable forms of evidence may include a copy of the completed annual work plan (including modifications if any), dated work orders, dated invoices, or dated inspection records. (R7)

4 circumstances that are beyond the control of a Transmission Owner include but are not limited to natural disasters such as earthquakes, fires, tornados, hurricanes, landslides, major storms as defined either by the TO or an applicable regulatory body, ice storms, and floods; arboricultural, horticultural or agricultural activities.

Rationale This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. An annual vegetation work plan allows for work to be modified for changing conditions, taking into consideration anticipated growth of vegetation and all other environmental factors, provided that the changes do not violate the encroachment within the MVCD.



CCoommpplliiaannccee

Compliance Enforcement Authority

Regional Entity

Compliance Monitoring and Enforcement Processes:

Compliance Audits Self-Certifications Spot Checking Compliance Violation Investigations Self-Reporting Complaints Periodic Data Submittals

Evidence Retention

The Transmission Owner retains data or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

The Transmission Owner retains data or evidence to show compliance with Requirement R4, Measure M4 for most recent 12 months of operator logs or most recent 3 months of voice recordings or transcripts of voice recordings, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

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

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

Additional Compliance Information

Periodic Data Submittal: The Transmission Owner will submit a quarterly report to its Regional Entity, or the Regional Entity’s designee, identifying all Sustained Outages of applicable transmission lines determined by the Transmission Owner to have been caused by vegetation, except as excluded in footnote 2, which includes as a minimum, the following:

o The name of the circuit(s), the date, time and duration of the outage; the voltage of the circuit; a description of the cause of the outage; the category associated with the Sustained Outage; other pertinent comments; and any countermeasures taken by the Transmission Owner.

A Sustained Outage is to be categorized as one of the following:

o Category 1A — Grow-ins: Sustained Outages caused by vegetation growing into applicable transmission lines, that are identified as an element of an IROL or Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;



o Category 1B — Grow-ins: Sustained Outages caused by vegetation growing into applicable transmission lines, but are not identified as an element of an IROL or Major WECC Transfer Path, by vegetation inside and/or outside of the ROW;

o Category 2A — Fall-ins: Sustained Outages caused by vegetation falling into applicable transmission lines that are identified as an element of an IROL or Major WECC Transfer Path, from within the ROW;

o Category 2B — Fall-ins: Sustained Outages caused by vegetation falling into applicable transmission lines, but are not identified as an element of an IROL or Major WECC Transfer Path, from within the ROW;

o Category 3 — Fall-ins: Sustained Outages caused by vegetation falling into applicable transmission lines from outside the ROW;

o Category 4A — Blowing together: Sustained Outages caused by vegetation and applicable transmission lines that are identified as an element of an IROL or Major WECC Transfer Path, blowing together from within the ROW.

o Category 4B — Blowing together: Sustained Outages caused by vegetation and applicable transmission lines, but are not identified as an element of an IROL or Major WECC Transfer Path, blowing together from within the ROW.

The Regional Entity will report the outage information provided by Transmission Owners, as per the above, quarterly to NERC, as well as any actions taken by the Regional Entity as a result of any of the reported Sustained Outages.



Time Horizons, Violation Risk Factors, and Violation Severity Levels

Table 1

R# Time Horizon

VRF Violation Severity Level

Lower Moderate High Severe

R1 Real-time High





R2 Real-time Medium





R3 Long-Term Planning Lower

The Transmission Owner has maintenance strategies or documented procedures or processes or specifications but has not accounted for the inter-relationships between

The Transmission Owner has maintenance strategies or documented procedures or processes or specifications but has not accounted for the

The Transmission Owner does not have any maintenance strategies or documented procedures or processes or specifications used to prevent the



vegetation growth rates, vegetation control methods, and inspection frequency, for the Transmission Owner’s applicable lines.

movement of transmission line conductors under their Rating and all Rated Electrical Operating Conditions, for the Transmission Owner’s applicable lines.

encroachment of vegetation into the MVCD, for the Transmission Owner’s applicable lines.

R4 Real-time Medium

The Transmission Owner experienced a confirmed vegetation threat and notified the control center holding switching authority for that transmission line, but there was intentional delay in that notification.

The Transmission Owner experienced a confirmed vegetation threat and did not notify the control center holding switching authority for that transmission line.


The Transmission Owner did not take corrective action when it was constrained from performing planned vegetation work where a transmission line was put at potential risk.


The Transmission Owner failed to inspect 5% or less of its applicable transmission lines (measured in units of choice - circuit, pole line, line miles or

The Transmission Owner failed to inspect more than 5% up to and including 10% of its applicable transmission lines (measured in units of choice - circuit, pole line, line miles or kilometers, etc.).

The Transmission Owner failed to inspect more than 10% up to and including 15% of its applicable transmission lines (measured in units of choice - circuit, pole line, line miles or kilometers, etc.).

The Transmission Owner failed to inspect more than 15% of its applicable transmission lines (measured in units of choice - circuit, pole line, line miles or kilometers, etc.).



kilometers, etc.)


The Transmission Owner failed to complete up to 5% of its annual vegetation work plan (including modifications if any).



The Transmission Owner failed to complete more than 15% of its annual vegetation work plan (including modifications if any).



VVaarriiaanncceess

None. IInntteerrpprreettaattiioonnss

None.



GGuuiiddeelliinnee aanndd TTeecchhnniiccaall BBaassiiss Requirements R1 and R2: R1 and R2 are performance-based requirements. The reliability objective or outcome to be achieved is the prevention of vegetation encroachments within a minimum distance of transmission lines. Content-wise, R1 and R2 are the same requirements; however, they apply to different Facilities. Both R1 and R2 require each Transmission Owner to manage vegetation to prevent encroachment within the Minimum Vegetation Clearance Distance (“MVCD”) of transmission lines. R1 is applicable to lines “identified as an element of an Interconnection Reliability Operating Limit (IROL) or Major Western Electricity Coordinating Council (WECC) transfer path (operating within Rating and Rated Electrical Operating Conditions) to avoid a Sustained Outage”. R2 applies to all other applicable lines that are not an element of an IROL or Major WECC Transfer Path.

The separation of applicability (between R1 and R2) recognizes that an encroachment into the MVCD of an IROL or Major WECC Transfer Path transmission line is a greater risk to the electric transmission system. Applicable lines that are not an element of an IROL or Major WECC Transfer Path are required to be clear of vegetation but these lines are comparatively less operationally significant. As a reflection of this difference in risk impact, the Violation Risk Factors (VRFs) are assigned as High for R1 and Medium for R2.

These requirements (R1 and R2) state that if vegetation encroaches within the distances in Table 1 in Appendix 1 of this supplemental Transmission Vegetation Management Standard FAC-003-2 Technical Reference document, it is in violation of the standard. Table 2 tabulates the distances necessary to prevent spark-over based on the Gallet equations as described more fully in Appendix 1 below.

These requirements assume that transmission lines and their conductors are operating within their Rating. If a line conductor is intentionally or inadvertently operated beyond its Rating (potentially in violation of other standards), the occurrence of a clearance encroachment may occur. For example, emergency actions taken by a Transmission Operator or Reliability Coordinator to protect an Interconnection may cause the transmission line to sag more and come closer to vegetation, potentially causing an outage. Such vegetation-related outages are not a violation of these requirements.

Evidence of violation of Requirement R1 and R2 include real-time observation of a vegetation encroachment into the MVCD (absent a Sustained Outage), or a vegetation-related encroachment resulting in a Sustained Outage due to a fall-in from inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to blowing together of applicable lines and vegetation located inside the ROW, or a vegetation-related encroachment resulting in a Sustained Outage due to a grow-in. If an investigation of a Fault by a Transmission Owner confirms that a vegetation encroachment within the MVCD occurred, then it shall be considered the equivalent of a Real-time observation.

With this approach, the VSLs were defined such that they directly correlate to the severity of a failure of a Transmission Owner to manage vegetation and to the corresponding performance level of the Transmission Owner’s vegetation program’s ability to meet the goal of “preventing a Sustained Outage that could lead to Cascading.” Thus violation severity increases with a Transmission Owner’s inability to meet this goal and its potential of leading to a Cascading



event. The additional benefits of such a combination are that it simplifies the standard and clearly defines performance for compliance. A performance-based requirement of this nature will promote high quality, cost effective vegetation management programs that will deliver the overall end result of improved reliability to the system.

Multiple Sustained Outages on an individual line can be caused by the same vegetation. For example, a limb may only partially break and intermittently contact a conductor. Such events are considered to be a single vegetation-related Sustained Outage under the Standard where the Sustained Outages occur within a 24 hour period.

The MVCD is a calculated minimum distance stated in feet (or meters) to prevent spark-over, for various altitudes and operating voltages that is used in the design of Transmission Facilities. Keeping vegetation from entering this space will prevent transmission outages. Requirement R3: Requirement R3 is a competency based requirement concerned with the maintenance strategies, procedures, processes, or specifications, a Transmission Owner uses for vegetation management.

An adequate transmission vegetation management program formally establishes the approach the Transmission Owner uses to plan and perform vegetation work to prevent transmission Sustained Outages and minimize risk to the Transmission System. The approach provides the basis for evaluating the intent, allocation of appropriate resources and the competency of the Transmission Owner in managing vegetation. There are many acceptable approaches to manage vegetation and avoid Sustained Outages. However, the Transmission Owner must be able to state what its approach is and how it conducts work to maintain clearances.

An example of one approach commonly used by industry is ANSI Standard A300, part 7. However, regardless of the approach a utility uses to manage vegetation, any approach a Transmission Owner chooses to use will generally contain the following elements:

1. the maintenance strategy used (such as minimum vegetation-to-conductor distance or maximum vegetation height) to ensure that MVCD clearances are never violated.

2. the work methods that the Transmission Owner uses to control vegetation

3. a stated Vegetation Inspection frequency

4. an annual work plan The conductor’s position in space at any point in time is continuously changing as a reaction to a number of different loading variables. Changes in vertical and horizontal conductor positioning are the result of thermal and physical loads applied to the line. Thermal loading is a function of line current and the combination of numerous variables influencing ambient heat dissipation including wind velocity/direction, ambient air temperature and precipitation. Physical loading applied to the conductor affects sag and sway by combining physical factors such as ice and wind loading. The movement of the transmission line conductor and the MVCD is illustrated in Figure 1 below.



Figure 1

Cross-section view of a single conductor at a given point along the span showing six possible conductor positions due to movement resulting from thermal and mechanical loading.

Requirement R4: R4 is a risk-based requirement. It focuses on preventative actions to be taken by the Transmission Owner for the mitigation of Fault risk when a vegetation threat is confirmed. R4 involves the notification of potentially threatening vegetation conditions, without any intentional delay, to the control center holding switching authority for that specific transmission line. Examples of acceptable unintentional delays may include communication system problems (for example, cellular service or two-way radio disabled), crews located in remote field locations with no communication access, delays due to severe weather, etc. Confirmation is key that a threat actually exists due to vegetation. This confirmation could be in the form of a Transmission Owner’s employee who personally identifies such a threat in the field. Confirmation could also be made by sending out an employee to evaluate a situation reported by a landowner. Vegetation-related conditions that warrant a response include vegetation that is near or encroaching into the MVCD (a grow-in issue) or vegetation that could fall into the transmission conductor (a fall-in issue). A knowledgeable verification of the risk would include an assessment of the possible sag or movement of the conductor while operating between no-load conditions and its rating. The Transmission Owner has the responsibility to ensure the proper communication between field personnel and the control center to allow the control center to take the appropriate action until the vegetation threat is relieved. Appropriate actions may include a temporary reduction in the line loading, switching the line out of service, or positioning the system in recognition of the increasing risk of outage on that circuit. The notification of the threat should be communicated in terms of minutes or hours as opposed to a longer time frame for corrective action plans (see R5).



All potential grow-in or fall-in vegetation-related conditions will not necessarily cause a Fault at any moment. For example, some Transmission Owners may have a danger tree identification program that identifies trees for removal with the potential to fall near the line. These trees would not require notification to the control center unless they pose an immediate fall-in threat. Requirement R5: R5 is a risk-based requirement. It focuses upon preventative actions to be taken by the Transmission Owner for the mitigation of Sustained Outage risk when temporarily constrained from performing vegetation maintenance. The intent of this requirement is to deal with situations that prevent the Transmission Owner from performing planned vegetation management work and, as a result, have the potential to put the transmission line at risk. Constraints to performing vegetation maintenance work as planned could result from legal injunctions filed by property owners, the discovery of easement stipulations which limit the Transmission Owner’s rights, or other circumstances. This requirement is not intended to address situations where the transmission line is not at potential risk and the work event can be rescheduled or re-planned using an alternate work methodology. For example, a land owner may prevent the planned use of chemicals on non-threatening, low growth vegetation but agree to the use of mechanical clearing. In this case the Transmission Owner is not under any immediate time constraint for achieving the management objective, can easily reschedule work using an alternate approach, and therefore does not need to take interim corrective action. However, in situations where transmission line reliability is potentially at risk due to a constraint, the Transmission Owner is required to take an interim corrective action to mitigate the potential risk to the transmission line. A wide range of actions can be taken to address various situations. General considerations include:

Identifying locations where the Transmission Owner is constrained from performing planned vegetation maintenance work which potentially leaves the transmission line at risk.

Developing the specific action to mitigate any potential risk associated with not performing the vegetation maintenance work as planned.

Documenting and tracking the specific action taken for each location.

In developing the specific action to mitigate the potential risk to the transmission line the Transmission Owner could consider location specific measures such as modifying the inspection and/or maintenance intervals. Where a legal constraint would not allow any vegetation work, the interim corrective action could include limiting the loading on the transmission line.

The Transmission Owner should document and track the specific corrective action taken at each location. This location may be indicated as one span, one tree or a combination of spans on one property where the constraint is considered to be temporary.



Requirement R6: R6 is a risk-based requirement. This requirement sets a minimum time period for completing Vegetation Inspections that fits general industry practice. In addition, the fact that Vegetation Inspections can be performed in conjunction with general line inspections further facilitates a Transmission Owner’s ability to meet this requirement. However, the Transmission Owner may determine that more frequent inspections are needed to maintain reliability levels, dependent upon such factors as anticipated growth rates of the local vegetation, length of the growing season for the geographical area, limited ROW width, and rainfall amounts. Therefore it is expected that some transmission lines may be designated with a higher frequency of inspections. The VSL for Requirement R6 has VSL categories ranked by the percentage of the required ROW inspections completed. To calculate the percentage of inspection completion, the Transmission Owner may choose units such as: line miles or kilometers, circuit miles or kilometers, pole line miles, ROW miles, etc. For example, when a Transmission Owner operates 2,000 miles of 230 kV transmission lines this Transmission Owner will be responsible for inspecting all 2,000 miles of 230 kV transmission lines at least once during the calendar year. If one of the included lines was 100 miles long, and if it was not inspected during the year, then the amount failed to inspect would be 100/2000 = 0.05 or 5%. The “Low VSL” for R6 would apply in this example. Requirement R7: R7 is a risk-based requirement. The Transmission Owner is required to implement an annual work plan for vegetation management to accomplish the purpose of this standard. Modifications to the work plan in response to changing conditions or to findings from vegetation inspections may be made and documented provided they do not put the transmission system at risk. The annual work plan requirement is not intended to necessarily require a “span-by-span”, or even a “line-by-line” detailed description of all work to be performed. It is only intended to require that the Transmission Owner provide evidence of annual planning and execution of a vegetation management maintenance approach which successfully prevents encroachment of vegetation into the MVCD. The ability to modify the work plan allows the Transmission Owner to change priorities or treatment methodologies during the year as conditions or situations dictate. For example recent line inspections may identify unanticipated high priority work, weather conditions (drought) could make herbicide application ineffective during the plan year, or a major storm could require redirecting local resources away from planned maintenance. This situation may also include complying with mutual assistance agreements by moving resources off the Transmission Owner’s system to work on another system. Any of these examples could result in acceptable deferrals or additions to the annual work plan. Modifications to the annual work plan must always ensure the reliability of the electric Transmission system. In general, the vegetation management maintenance approach should use the full extent of the Transmission Owner’s easement, fee simple and other legal rights allowed. A comprehensive approach that exercises the full extent of legal rights on the ROW is superior to incremental



management in the long term because it reduces the overall potential for encroachments, and it ensures that future planned work and future planned inspection cycles are sufficient. When developing the annual work plan the Transmission Owner should allow time for procedural requirements to obtain permits to work on federal, state, provincial, public, tribal lands. In some cases the lead time for obtaining permits may necessitate preparing work plans more than a year prior to work start dates. Transmission Owners may also need to consider those special landowner requirements as documented in easement instruments. This requirement sets the expectation that the work identified in the annual work plan will be completed as planned. Therefore, deferrals or relevant changes to the annual plan shall be documented. Depending on the planning and documentation format used by the Transmission Owner, evidence of successful annual work plan execution could consist of signed-off work orders, signed contracts, printouts from work management systems, spreadsheets of planned versus completed work, timesheets, work inspection reports, or paid invoices. Other evidence may include photographs, and walk-through reports.



FFAACC--000033 —— TTAABBLLEE 22 —— MMiinniimmuumm VVeeggeettaattiioonn CClleeaarraannccee DDiissttaanncceess ((MMVVCCDD))55 For Alternating Current Voltages

( AC ) Nominal System Voltage (kV)

( AC ) Maximum System Voltage (kV)

MVCD feet

(meters)

sea level

MVCD


(914.4m)

MVCD


(1219.2m)

MVCD


(1524m)

MVCD


(1828.8m)

MVCD


(2133.6m)

MVCD


(2438.4m)

MVCD


(2743.2m)

MVCD

feet (meters) 10,000ft (3048m)

MVCD


(3352.8m)

765 800 8.06ft

(2.46m) 8.89ft

(2.71m) 9.17ft

(2.80m) 9.45ft

(2.88m) 9.73ft

(2.97m) 10.01ft (3.05m)

10.29ft (3.14m)

10.57ft (3.22m)

10.85ft (3.31m)

11.13ft (3.39m)

500 550 5.06ft

(1.54m) 5.66ft

(1.73m) 5.86ft

(1.79m) 6.07ft

(1.85m) 6.28ft

(1.91m) 6.49ft

(1.98m) 6.7ft

(2.04m) 6.92ft

(2.11m) 7.13ft

(2.17m) 7.35ft

(2.24m)

345 362 3.12ft

(0.95m) 3.53ft

(1.08m) 3.67ft

(1.12m) 3.82ft

(1.16m) 3.97ft

(1.21m) 4.12ft

(1.26m) 4.27ft

(1.30m) 4.43ft

(1.35m) 4.58ft

(1.40m) 4.74ft

(1.44m)

230 242 2.97ft

(0.91m) 3.36ft

(1.02m) 3.49ft

(1.06m) 3.63ft

(1.11m) 3.78ft

(1.15m) 3.92ft

(1.19m) 4.07ft

(1.24m) 4.22ft

(1.29m) 4.37ft

(1.33m) 4.53ft

(1.38m)

161* 169 2ft

(0.61m) 2.28ft

(0.69m) 2.38ft

(0.73m) 2.48ft

(0.76m) 2.58ft

(0.79m) 2.69ft

(0.82m) 2.8ft

(0.85m) 2.91ft

(0.89m) 3.03ft

(0.92m) 3.14ft

(0.96m)

138* 145 1.7ft

(0.52m) 1.94ft

(0.59m) 2.03ft

(0.62m) 2.12ft

(0.65m) 2.21ft

(0.67m) 2.3ft

(0.70m) 2.4ft

(0.73m) 2.49ft

(0.76m) 2.59ft

(0.79m) 2.7ft

(0.82m)

115* 121 1.41ft

(0.43m) 1.61ft

(0.49m) 1.68ft

(0.51m) 1.75ft

(0.53m) 1.83ft

(0.56m) 1.91ft

(0.58m) 1.99ft

(0.61m) 2.07ft

(0.63m) 2.16ft

(0.66m) 2.25ft

(0.69m)

88* 100 1.15ft

(0.35m) 1.32ft

(0.40m) 1.38ft

(0.42m) 1.44ft

(0.44m) 1.5ft

(0.46m) 1.57ft

(0.48m) 1.64ft

(0.50m) 1.71ft

(0.52m) 1.78ft

(0.54m) 1.86ft

(0.57m)

69* 72 0.82ft

(0.25m) 0.94ft

(0.29m) 0.99ft

(0.30m) 1.03ft

(0.31m) 1.08ft

(0.33m) 1.13ft

(0.34m) 1.18ft

(0.36m) 1.23ft

(0.37m) 1.28ft

(0.39m) 1.34ft

(0.41m)

* Such lines are applicable to this standard only if PC has determined such per FAC-014 (refer to the Applicability Section above).

5 The distances in this Table are the minimums required to prevent Flash-over; however prudent vegetation maintenance practices dictate that substantially greater distances will be achieved at time of vegetation maintenance.



TTaabbllee 22 ((ccoonntt..)) —— MMiinniimmuumm VVeeggeettaattiioonn CClleeaarraannccee DDiissttaanncceess ((MMVVCCDD)) For Direct Current Voltages

( DC ) Nominal Pole

to Ground Voltage

(kV)

MVCD feet

(meters)

sea level

MVCD feet

(meters) 3,000ft

(914.4m) Alt.

MVCD feet

(meters) 4,000ft

(1219.2m) Alt.

MVCD feet

(meters) 5,000ft

(1524m) Alt.

MVCD feet

(meters) 6,000ft

(1828.8m) Alt.

MVCD feet

(meters) 7,000ft

(2133.6m) Alt.

MVCD feet

(meters) (8,000ft

(2438.4m) Alt.

MVCD feet

(meters) 9,000ft

(2743.2m) Alt.

MVCD feet

(meters) 10,000ft (3048m)

Alt.

MVCD feet

(meters) 11,000ft

(3352.8m) Alt.

±750 13.92ft (4.24m)

15.07ft (4.59m)

15.45ft (4.71m)

15.82ft (4.82m)

16.2ft (4.94m)

16.55ft (5.04m)

16.9ft (5.15m)

17.27ft (5.26m)

17.62ft (5.37m)

17.97ft (5.48m)

±600 10.07ft (3.07m)

11.04ft (3.36m)

11.35ft (3.46m)

11.66ft (3.55m)

11.98ft (3.65m)

12.3ft (3.75m)

12.62ft (3.85m)

12.92ft (3.94m)

13.24ft (4.04m)

(13.54ft 4.13m)

±500 7.89ft

(2.40m) 8.71ft

(2.65m) 8.99ft

(2.74m) 9.25ft

(2.82m) 9.55ft

(2.91m) 9.82ft

(2.99m) 10.1ft

(3.08m) 10.38ft (3.16m)

10.65ft (3.25m)

10.92ft (3.33m)

±400 4.78ft

(1.46m) 5.35ft

(1.63m) 5.55ft

(1.69m) 5.75ft

(1.75m) 5.95ft

(1.81m) 6.15ft

(1.87m) 6.36ft

(1.94m) 6.57ft

(2.00m) 6.77ft

(2.06m) 6.98ft

(2.13m)

±250 3.43ft

(1.05m) 4.02ft

(1.23m) 4.02ft

(1.23m) 4.18ft

(1.27m) 4.34ft

(1.32m) 4.5ft

(1.37m) 4.66ft

(1.42m) 4.83ft

(1.47m) 5ft

(1.52m) 5.17ft

(1.58m)

Notes: The SDT determined that the use of IEEE 516-2003 in version 1 of FAC-003 was a misapplication. The SDT consulted specialists who advised that the Gallet Equation would be a technically justified method. The explanation of why the Gallet approach is more appropriate is explained in the paragraphs below. The drafting team sought a method of establishing minimum clearance distances that uses realistic weather conditions and realistic maximum transient over-voltages factors for in-service transmission lines. The SDT considered several factors when looking at changes to the minimum vegetation to conductor distances in FAC-003-1:



avoid the problem associated with referring to tables in another standard (IEEE-516-2003) transmission lines operate in non-laboratory environments (wet conditions) transient over-voltage factors are lower for in-service transmission lines than for inadvertently re-energized transmission lines

with trapped charges. FAC-003-1 uses the minimum air insulation distance (MAID) without tools formula provided in IEEE 516-2003 to determine the minimum distance between a transmission line conductor and vegetation. The equations and methods provided in IEEE 516 were developed by an IEEE Task Force in 1968 from test data provided by thirteen independent laboratories. The distances provided in IEEE 516 Tables 5 and 7 are based on the withstand voltage of a dry rod-rod air gap, or in other words, dry laboratory conditions. Consequently, the validity of using these distances in an outside environment application has been questioned. FAC-003-01 allowed Transmission Owners to use either Table 5 or Table 7 to establish the minimum clearance distances. Table 5 could be used if the Transmission Owner knew the maximum transient over-voltage factor for its system. Otherwise, Table 7 would have to be used. Table 7 represented minimum air insulation distances under the worst possible case for transient over-voltage factors. These worst case transient over-voltage factors were as follows: 3.5 for voltages up to 362 kV phase to phase; 3.0 for 500 - 550 kV phase to phase; and 2.5 for 765 to 800 kV phase to phase. These worst case over-voltage factors were also a cause for concern in this particular application of the distances. In general, the worst case transient over-voltages occur on a transmission line that is inadvertently re-energized immediately after the line is de-energized and a trapped charge is still present. The intent of FAC-003 is to keep a transmission line that is in service from becoming de-energized (i.e. tripped out) due to spark-over from the line conductor to nearby vegetation. Thus, the worst case transient overvoltage assumptions are not appropriate for this application. Rather, the appropriate over voltage values are those that occur only while the line is energized. Typical values of transient over-voltages of in-service lines, as such, are not readily available in the literature because they are negligible compared with the maximums. A conservative value for the maximum transient over-voltage that can occur anywhere along the length of an in-service ac line is approximately 2.0 per unit. This value is a conservative estimate of the transient over-voltage that is created at the point of application (e.g. a substation) by switching a capacitor bank without pre-insertion devices (e.g. closing resistors). At voltage levels where capacitor banks are not very common (e.g. 362 kV), the maximum transient over-voltage of an in-service ac line are created by fault initiation on adjacent ac lines and shunt reactor bank switching. These transient voltages are usually 1.5 per unit or less.



Even though these transient over-voltages will not be experienced at locations remote from the bus at which they are created, in order to be conservative, it is assumed that all nearby ac lines are subjected to this same level of over-voltage. Thus, a maximum transient over-voltage factor of 2.0 per unit for transmission lines operated at 242 kV and below is considered to be a realistic maximum in this application. Likewise, for ac transmission lines operated at 362 kV and above a transient over-voltage factor of 1.4 per unit is considered a realistic maximum. The Gallet Equations are an accepted method for insulation coordination in tower design. These equations are used for computing the required strike distances for proper transmission line insulation coordination. They were developed for both wet and dry applications and can be used with any value of transient over-voltage factor. The Gallet Equation also can take into account various air gap geometries. This approach was used to design the first 500 kV and 765 kV lines in North America [1]. If one compares the MAID using the IEEE 516-2003 Table 7 (table D.5 for English values) with the critical spark-over distances computed using the Gallet wet equations, for each of the nominal voltage classes and identical transient over-voltage factors, the Gallet equations yield a more conservative (larger) minimum distance value. Distances calculated from either the IEEE 516 (dry) formulas or the Gallet “wet” formulas are not vastly different when the same transient overvoltage factors are used; the “wet” equations will consistently produce slightly larger distances than the IEEE 516 equations when the same transient overvoltage is used. While the IEEE 516 equations were only developed for dry conditions the Gallet equations have provisions to calculate spark-over distances for both wet and dry conditions. While EPRI is currently trying to establish empirical data for spark-over distances to live vegetation, there are no spark-over formulas currently derived expressly for vegetation to conductor minimum distances. Therefore the SDT chose a proven method that has been used in other EHV applications. The Gallet equations relevance to wet conditions and the selection of a Transient Overvoltage Factor that is consistent with the absence of trapped charges on an in-service transmission line make this methodology a better choice. The following table is an example of the comparison of distances derived from IEEE 516 and the Gallet equations using various transient overvoltage values.



Comparison of spark-over distances computed using Gallet wet equations vs.

IEEE 516-2003 MAID distances using various transient over-voltage factors

Table 5


765 800 1.4 8.89 8.65 500 550 1.4 5.65 4.92 345 362 1.4 3.52 3.13 230 242 2.0 3.35 2.8

115 121 2.0 1.6 1.4

Table 5

(historical maximums) ( AC ) ( AC ) Transient Clearance (ft.) IEEE 516

Nom System Max System Over-voltage Gallet (wet) MAID (ft) Voltage (kV) Voltage (kV) Factor (T) @ Alt. 3000 feet @ Alt. 3000 feet

765 800 2.0 14.36 13.95 500 550 2.4 11.0 10.07 345 362 3.0 8.55 7.47 230 242 3.0 5.28 4.2

115 121 3.0 2.46 2.1



Table 7


765 800 2.5 20.25 20.4 500 550 3.0 15.02 14.7 345 362 3.5 10.42 9.44

230 242 3.5 6.32 5.14

115 121 3.5 2.90 2.45

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Standard Authorization Request Form Title of Proposed Standard Various Standards Containing GO/GOP and TO/TOP Requirements

Request Date January 15, 2010

SC Approval Date January 20, 2010

Revised Date November 30, 2010

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

Name Ad Hoc Group for Generator Requirements at the Transmission Interface

New Standard

Primary Contact Scott Helyer

Revision to existing Standards

Telephone 817-462-1512

Fax

Withdrawal of existing Standard

E-mail [email protected] Urgent Action

Attachment 4bi Revised SAR for GO-TO Project


Standards Authorization Request Form

SAR–2

Purpose (Describe what the standard action will achieve in support of bulk power system reliability.)

The proposed changes to the requirements and the addition of new requirements will add significant clarity to Generator Owners and Generator Operators regarding their reliability standard obligations at the interface with the interconnected grid.

Industry Need (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.)

Significant industry concern exists regarding the application of Transmission Owner and Transmission Operator requirements, and more generally, to the registration of Generator Owners and Generator Operators as Transmission Owners and Transmission Operators, based on the facilities that connect the generators to the interconnected grid. The final report of the Ad Hoc Group for Generator Requirements at the Transmission Interface evaluated the issue and proposes a number of changes that adds much needed clarity on the requirements for Generator Interconnection Facilities. Absent these revisions and additional requirements, Generator Owners and Generator Operators are subject to what some believe to be inappropriate registration as Transmission Owners and Transmission Operators to ensure coverage for certain reliability requirements. The modifications and additions recommended wholly and directly address the requirements for Generator Owners and Generator Operators regarding its Generator Interconnection Facilities, and add particular focus on the operation of the interface point at which operating responsibility shifts from the Generator Operator to the Transmission Operator.

The proposal also modifies certain of NERC's existing glossary terms and adds new terms to support the standards modifications.

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

32 NERC Reliability Standards contain language regarding generators or generating facilities for which greater clarity regarding its Generator Interconnection Facilities would ensure no reliability gap exists

12 requirements in FAC-003-1 - Transmission Vegetation Management should have their applicability expanded to include Generator Owners.

2 NERC Reliability Standards should have their applicability expanded to include Generator Operators to address general reliability gaps not attributable to their Generator Interconnection Facilities.

8 new Reliability Standard Requirements should be added to ensure the responsibilities for owning and operating the Generator Interconnection Facility are clear, and to address certain requirements that should apply to all generators regardless of interconnection configuration.

New NERC Glossary definitions are needed for Generator Interconnection Facility and Generator Interconnection Operational Interface, as well as modifications to Vegetation Inspection, Right-of-Way, Generator Owner, Generator Operator, and Transmission

Detailed Description (Provide a description of the proposed project with sufficient details for the standard drafting team to execute the SAR.)

Refer to Final Report of the Ad hoc Group for Generator Requirements at the Transmission Interface.

Revisions to the latest versions of the following standards are included in the report and redline standard changes are included to accompany this SAR:

BAL-005

CIP-002

EOP-001, -003, -004, -008

FAC-001, -003, -008, -009


SAR–3

IRO-005

MOD-010, -012

PER-001, -002

PRC-001, -004, -005

TOP-001, -002, -003, -004, -008

VAR-001, -002


SAR–4

Reliability Functions

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

Reliability Assurer

Monitors and evaluates the activities related to planning and operations, and coordinates activities of Responsible Entities to secure the reliability of the bulk power system within a Reliability Assurer Area and adjacent areas.

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 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.

Load-Serving Entity

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


SAR–5

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

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


SAR–6

Related Standards

Standard No. Explanation

Related SARs

SAR ID Explanation

Regional Variances

Region Explanation

ERCOT

FRCC

MRO

NPCC

SERC

RFC

SPP

WECC

1

Next Steps: Project 2010‐07

Generator Requirements at the Transmission Interface

Project Goal: Simultaneous implementation of a set of NERC Glossary changes and related

changes to standards to add significant clarity for Generator Owners and Generator Operators

regarding their reliability standard obligations at the interface between the generation and

transmission facility. In this case, phased implementation is not an option as it would result in

significant mismatches that would adversely impact both registration and compliance.

To complete the standards and Glossary change recommendations proposed by the Generator

Requirements at the Transmission Interface Ad Hoc Task Force (“Ad Hoc Task Force”), the SAR

DT proposes that it be appointed as the Standards Drafting Team (SDT) for Project 2010‐07 to

move this project ahead expeditiously. While the SAR DT has significant diversity, consideration

may be given to further diversify the team’s perspective by adding one or two members from

WECC, TRE, ERCOT, the SPP, or the NPCC Regions.

Once appointed, the SDT will utilize the proposed standards and Glossary changes proposed by

the Ad Hoc Task Force as a basis for determining a set of final solutions to the issues identified

in the SAR. In cases where the proposed standard changes are applied to standards that have

been recently modified, the SDT will use the latest version of the standard to incorporate the

proposed change and preserve the intent of the recommendations from the Ad Hoc Task Force

Report. Such instances have been noted in the accompanying table. Further, the SDT will

evaluate, in consultation with NERC and FERC staff, whether any additional standards should be

modified or whether some recommendations should be deleted based on regulatory decisions

rendered in the cases of other Generator Owners and Generator Operators that have been

registered as Transmission Owners and Transmission Operators (i.e. the Harquahala

settlement/order).

The SAR DT believes that the set of standards and Glossary changes should be handled within

the appointed SDT, but consultation and close coordination will be required with other SDTs to

ensure that multiple changes to the same standards will work in concert and enable acceptance

of all the proposed changes by the respective ballot pools.

After the significant industry support of this project’s importance in comments on the 2011‐

2013 Reliability Standards and Development Plan, we feel even more strongly about the

urgency of these changes. A proposed timeline of work follows, and a table outlining the SAR

DT’s proposed scope of work is attached. In addition to modifications to the cited standards,

the team proposes the addition of the terms, ‘Generator Interconnection Facility’ and

Attachment 4bii Project 2010-07 – Next Steps


Next Steps: Project 2010‐07 ‐ Generator Requirements at the Transmission Interface

2

‘Generator Interconnection Operational Interface’ to the NERC Glossary, along with the

modification of Vegetation Inspection, Right‐of‐Way, Generator Owner, Generator Operator,

and Transmission.

Proposed Timeline

By January 1, 2011: SC to approve proceeding with Standards drafting

o Appoint current team as the official SDT.

January 2011: First SDT meeting

o Will include registry personnel from NERC and Regional Entities to obtain general

agreement that the Ad Hoc Task Force Report changes proposed for standards will

prevent future GO/GOPs from being declared TO/TOPs. The SDT will also agree upon

logistics and detailed timing for the required Glossary and Standards changes.

By May 1, 2011: SDT to incorporate comments from SAR posting on proposed changes to

standards and develop complete drafts of revised standards. SDT will collect informal feedback

on preliminary drafts through other drafting teams, technical committees, etc. Drafts prepared

will include:

o Applicability

o Requirements

o Measures

o VSLs

o VRFs

o Implementation Plan

May 1, 2011: Post for 30‐day comment period

Through August 15, 2011: Standard development

August 15, 2011: Post for 45‐day comment period

o September 5‐15, 2011 (last 10 days): Initial Ballot

Through November 15, 2011: Standard development

November 15, 2011: Post for 30‐day comment period

o December 5‐15, 2011 (last 10 days): Successive Ballot

Through January 15, 2012: Make final changes necessary

January 15‐25, 2012: Recirculation Ballot

January 26, 2012: Standard(s) ready for BOT action


3

Standard Number and Name

Current Project: Stage Scope

(per the original Ad Hoc Report)

Benefit Notes

BAL‐005‐0b – Automatic Generation Control

2010‐14: Standard draftingModification to R1, part

1.1

Ensures that the Generator Interconnection

Facility is included in metered boundaries of BA

Area

Consider adding “including its Generator

Interconnection Facility” to the VSL for R1; no

changes to Applicability, Measures, Evidence

Retention

CIP‐002 – Cyber Security, Critical Cyber Asset

Identification 2008‐06: Initial ballot

Modification to criteria for determining critical assets (would be modification to R1 parts R1.2.3 and R1.2.4

in Version 1)


Facility is assigned a criticality

Need to wait until V5 work begins to “hop on” this

project

COM‐001 – Telecommunications

2006‐06: Comments, 3rd draft

‐‐ ‐‐

Was noted as applicable in the Harquahala order but not included in the original

Ad Hoc report; will be considered by SDT;

standards may have been balloted and filed by the time a 2010‐07 SDT is

appointed.

2009‐02: Standard drafting

COM‐002 – Communications and

Coordination

2006‐06: Comments, 3rd draft

‐‐ ‐‐




appointed.

2007‐02: Comments, initial

2009‐22: Interpretation: comments, initial


4




Benefit Notes

EOP‐001‐0 – Emergency Operations Planning

2009‐03: Standard draftingModification to R7, part

7.3

Ensures that the outages to the Generator

Interconnection Facility are included in the TOP and BAs’ coordination of

transmission and generator maintenance

schedules

No changes to Applicability, Measures, Evidence Retention, VSLs

EOP‐003‐1 – Load Shedding Plans

2009‐03: Standard drafting

Inclusion of Generator Operators under

Applicability; modification to R7

Ensures that the GOP coordinates automatic

load shedding throughout its area

Might also require a change to the Purpose; no changes to Measures,

Evidence Retention, VSLs

EOP‐004‐1 – Disturbance Reporting

2009‐01: Standard drafting Modification to R2

Ensures that the Generator Interconnection Facility is included when the RC, BA, TOP, GOP, or

LSE analyzes BES disturbances on its systems or facilities

Project 2009‐01 has proposed modifications to

EOP‐004 that would require changes to the Ad

Hoc Task Force’s suggestions; 2010‐07 SDT will need to reevaluate

changes and this standard’s inclusion in the

project.

EOP‐005 – System Restoration Plans

2006‐03: Pending FERC approval

‐‐ ‐‐


Ad Hoc report; will be considered by SDT

2009‐24: Interpretation, not posted for comment

EOP‐008‐0 – Plans for Loss of Control Center Functionality


Modification to R1, part 1.3

Ensures that the RC, TOP, and BA’s contingency plan addresses monitoring and

Project 2006‐04 has filed modifications to EOP‐008

that would require


5




Benefit Notes

control of the Generator Interconnection

Operational Interface

changes to the Ad Hoc Task Force’s suggestions; 2010‐07 SDT will need to reevaluate changes and

this standard’s inclusion in the project.

FAC‐001‐0 – Facility Connection Requirements

No current activity Modification to R1, part

1.1

Ensures that the Generator Interconnection Facility is included in the generation facilities for which the TO must address connection

requirements


FAC‐002‐0 – Coordination of Plans for New

Generation, Transmission, and End‐User Facilities

2010‐02: Assigned to Project 2010‐02, but no

activity ‐‐ ‐‐



FAC‐003 – Transmission Vegetation Management

Program 2007‐07: Initial ballot

Inclusion of Generator Owners and specific

Generator Interconnection Facilities under Applicability;

modifications to R1, R1 part 1.1, 1.2, 1.2.1, 1.2.2, 1.3, 1.4, and 1.5, R2, R3, and R3 part 3.2 and 3.3

Ensures that the GO and Generator Interconnection Facility are included in applicable vegetation

management requirements


FAC‐003 that would require changes to the Ad

Hoc Task Force’s suggestions. The 2010‐07

SDT will need to reevaluate changes and


FAC‐008 – Facility Ratings Methodology


Modifications to R1 and R 1 part 1.2.1




6




Benefit Notes

Facility is included in the TO and GO’s

documentation of its current methodology for developing Facility Ratings of its solely and jointly

owned Facilities

FAC‐008 that would require changes to the Ad

Hoc Task Force’s suggestions; 2010‐07 SDT will need to reevaluate

changes and this standard’s inclusion in the

project.

FAC‐009 – Establish and Communicate Facility

Ratings

2009‐06: Pending FERC approval; proposed for

retirement Modifications to R1 and R2

Ensures that the Generator Interconnection Facility is included in the solely and jointly owned Facilities for which the TO and GOP must establish and provide Facility

Ratings

Recommendations will not apply if FAC‐009 is retired; R1 and R2 from FAC‐009‐1 are accounted for in the

filed FAC‐008‐2 and will be reconsidered there

IRO‐001 – Reliability Coordination –

Responsibilities and Authorities

2006‐06: Comments, 3rd draft.

‐‐ ‐‐




appointed.

IRO‐002 – Reliability Coordination – Facilities

No activity ‐‐ ‐‐




7




Benefit Notes

IRO‐004 – Reliability Coordination –

Operations Planning 2009‐02: Standard drafting ‐‐ ‐‐



IRO‐005 – Reliability Coordination – Current

Day Operations

Project 2006‐06; proposed for retirement

Modification to R9; addition of a new requirement, R13

Ensures that the RC includes the Generator

Interconnection Facility in its coordination of pending

generation and transmission maintenance

outages; adds a requirement for the GOP to immediately inform the TOP of the status of the

SPS

Recommendations will not apply if IRO‐005 is retired;

R9 is proposed for retirement because of

redundancy with IRO‐004 and TOP‐003, both of which are already being

considered by the 2010‐07 team; the team will also consider whether the

proposed new R13 needs to be accounted for

elsewhere

MOD‐010 – Steady‐State Date for Modeling and

Simulation of the Interconnected

Transmission System

No current activity Modifications to R1 and R2

Ensures that GOs include information for both plants and Generator

Interconnection Facilities when they provide the

steady‐state modeling and simulation data to the Regional Reliability

Organizations, NERC, and those entities specified within the standard

No changes to Applicability, Measures, Evidence Retention, or

VSLs

MOD‐012 – Dynamics No current activity Modifications to R1 and R2 Ensures that GOs include No changes to


8




Benefit Notes

Date for Modeling and Simulation of the Interconnected

Transmission System

information for both plants and Generator

Interconnection Facilities when they provide the appropriate equipment

characteristics and system data in compliance with

the respective Interconnection‐wide

Regional dynamics system modeling and simulation data requirements and reporting procedures as defined in Reliability

Standard

Applicability, Measures, Evidence Retention, or

VSLs

PER‐001 – Operating Personnel Responsibility

and Authority

2007‐03: Comments, 4th draft; recommended for

retirement

Inclusion of Generator Operator under

Applicability; addition of new requirement, R2

Ensures that GOP operating personnel have the responsibility and authority to implement

real‐time actions to ensure the stable and reliable operation of the BES

Recommendations will not apply if PER‐001 is retired;

2010‐07 will consider whether the proposed new R2 needs to be

accounted for elsewhere

PER‐002 – Operating Personnel Training

FERC Order approved

retirement and replacement with PER‐

005‐1

Inclusion of Generator Operator under

Applicability; modification to R1; addition of new

requirement, R3

Ensures that GOPs are staffed with adequately

trained operating personnel and implement an initial and continuing training program for all operating personnel responsible for the

Recommendations do not apply now that PER‐002

has been retired; team will now consider PER‐005‐1 in

its stead.


9




Benefit Notes

Generator Interconnection Facility

PER‐003 – Operating Personnel Credentials

2007‐04: Recirculation ballot

‐‐ ‐‐



PER‐005 – System Personnel Training

No current activity ‐‐ ‐‐

Because PER‐002 was included in the Ad Hoc Task Force’s report and has been replaced with PER‐005‐1, the 2010‐07 SDT will consider PER‐005 for possible modifications

PRC‐001 – System Protection Coordination

2007‐06: Comments, 1st draft

Modifications to R1, R2, R3, R3 part 3.1, R5, and R5

part 5.1


Facility is included in coordinated system

protection

Proposed modifications to PRC‐001 would require changes to the Ad Hoc

Task Force’s suggestions; the 2010‐07 SDT will need to reevaluate changes and this standard’s inclusion in

the project.

PRC‐004 – Analysis and Mitigation of

Transmission and Generation Protection System Misoperations

No current activity Modification to R2

Ensures that the Generator Interconnection Facility is included in the

GO’s analysis of its generator Protection System Maintenance

Misoperations

No changes to Applicability, Measures, Evidence Retention, or

VSLs

PRC‐005 – Transmission 2007‐17: Successive ballot Modifications to R1 and R2 Ensures that Generator Proposed modifications to


10




Benefit Notes

and Generation Protection System

Maintenance and Testing

Interconnection Facilities are included in the transmission and

generation Protection Systems that are

maintained and tested

PRC‐005 would require changes to the Ad Hoc

Task Force’s suggestions; the 2010‐07 SDT will need to reevaluate changes and this standard’s inclusion in

the project.

TOP‐001 – Reliability Responsibilities and

Authorities

2007‐03: Comments, 4th draft

Modifications to R7 and R7 parts 7.1, 7.2, and 7.2; addition of R9 and R10

Ensures that the Generator Interconnection Facility is included in the BES facilities that should not be removed unless certain coordination

occurs; ensures that the GOP and TOP coordinate the operation of the

Generator Interconnection Facility in an emergency; ensures that the TOP has author over the operation

of the Generator Interconnection

Operational Interface

TOP‐001 has been modified in Project 2007‐03 and the changes are likely to be approved by the time a 2010‐07 SDT is appointed; the 2010‐07

team will need to reevaluate changes and


TOP‐002 – Normal Operations Planning


Modifications to R3 and R18; addition of a part

14.2 in R14

Ensures that Generator Interconnection Facilities are included in current operations plans and

procedures

TOP‐002 has been completely modified in Project 2007‐03 and the changes are likely to be approved by the time a

2010‐07 SDT is appointed; the 2010‐07 team will


11




Benefit Notes

need to reevaluate changes and this

standard’s inclusion in the project.

TOP‐003 – Planned Outage Coordination


Modifications to R1 and R1 part 1.1

Ensures that information for the Generator

Interconnections Facility is included in the planning outage information supplied by GOPs and

TOPs


2010‐07 SDT is appointed; the 2010‐07 team will need to reevaluate changes and this


TOP‐004 – Transmission Operations


Addition of R7

Ensures that the GOP operates its Generator Interconnection Facility within its applicable

ratings


2010‐07 SDT is appointed; the 2010‐07 team will need to reevaluate changes and this


TOP‐005 – Operational Reliability Information

2007‐03:Recommended for retirement

‐‐ ‐‐

Was noted as applicable in the Harquahala order but not included in the original Ad Hoc report; 2010‐07


12




Benefit Notes

team will consider whether the proposed

retired requirements were moved elsewhere and still need to be considered

TOP‐006 – Monitoring System Conditions

2007‐03: Recommended for retirement

‐‐ ‐‐

Was noted as applicable in the Harquahala order but not included in the original Ad Hoc report; 2010‐07

team will consider whether the proposed

retired requirements were moved elsewhere and still need to be considered

2010‐INT‐01: Interpretation, not posted

for comment

TOP‐008 – Response to Transmission Limit

Violations

2007‐03: Recommended for retirement

Inclusion of Generator Operators under

Applicability; addition of R5

Ensures that the GOP takes actions to

disconnect the Generator Interconnection Facility if the overload or abnormal

voltage or reactive condition persists and the equipment or Facility are endangers; ensures that the GOP communicates with the TOP and BA in

such cases

Recommendations will not apply if TOP‐008 is retired;

2010‐07 team will consider whether the proposed retired

requirements were moved elsewhere and still need to

be considered

VAR‐001 – Transmission Operations

2008‐01: Standard drafting Modification to R8

Ensures that the Generator Interconnection Facility is included in the TOP’s operation and



13




Benefit Notes

direction of capacitive and inductive reactive

resources within its area

VAR‐002 – Transmission Operations

2008‐01: Standard drafting Modification to R3 part 3.2

Ensures that the Generator Interconnection Facility is included among

the Reactive Power resources under the GOP’s

control


Status of All Interpretations (December 2, 2010)

Project/Standard R # Synopsis of Issue Ballot Status Last Action Next Action Project 2008‐10 ― Interpretation of CIP‐006‐1 for Progress Energy (Harry Tom)

R1.1 Does electronic security perimeter wiringexternal to a physical security perimeter have to be protected within a six‐wall boundary?

Initial ballot conducted and achieved a quorum and high approval Quorum: 79.92% Approval: 74.47%

Initial ballot ended October 12, 1009

Conduct recirculation ballot

Project 2009‐17 ― Interpretation of PRC‐004‐1 and PRC‐005‐1 for Y‐W Electric and Tri‐State G & T (Darrel Richardson)

R2 Is protection for a radially‐connected transformer protection system energized from the BES considered a transmission Protection System?

Initial ballot conducted and achieved a quorum and high enough approval: Quorum: 83.15 % Approval: 74.55 %

Recirculation ballot started November 19, 2010

TBD

Project 2009‐19 ― Interpretation of BAL‐002‐0 for NWPP Reserve Sharing Group (Andy Rodriquez)

R4 and R5 Seeks clarity on which disturbances are excluded from compliance and on the use of the phrase, “excluded from compliance evaluation.”

Initial ballot conducted and failed.Quorum: 89.83% Approval: 48.60%

Initial ballot ended February 26, 2010

Placed on hold by SC October , 2010

Project 2009‐22 ― Interpretation of COM‐002‐2 for the IRC (Howard Gugel)

R2 Are routine operating instructions considered “directives” or are “directives” limited to emergency operating conditions?

Posted for initial comment November 18, 2010

TBD

Project 2009‐23 ― Interpretation of CIP‐004‐2 for Army Corps of Engineers (Howard Gugel)

R3 Asks for clarity on acceptable sources of ID verification, periodicity of ID verifications, and 7 yr criminal checks.

Initial ballot conducted and failed.Quorum: 88.52 %

Approval: 63.43 %

Initial ballot ended April 8, 2010

Reopen ballot pool Post revised interpretation for parallel comment/ballot

Project 2009‐24 ― Interpretation of EOP‐005‐1 for FMPA (Howard Gugel)

R7 Asks for clarity on the use of the phrase, “verify the restoration procedure” and the term, “simulation” for TOPs without any black start facilities.

Balloted once and received low approval Jan 15, 2010: Quorum: 87.68% Approval: 17.79% (Interpretation revised)

Ballot pool closed April 21, 2010


Project 2009‐25 ― Interpretation of BAL‐001‐01 and BAL‐002‐0 by BPA (Howard Gugel)

R1 Does the WECC Automatic Time Error Control Procedure (WATEC) violate Requirement 1 of BAL‐001‐0?


Initial ballot ended January 15, 2010

Drafting team to report to SC in October, 2010

Project 2009‐26 ― Interpretation of CIP‐004‐1 for WECC (Howard Gugel)

R2‐R4 Asks for clarity with respect to “authorized access” as applied to temporary support from vendors. Do the training, risk assessment and access requirements specified in R2, R3, and R4 apply


Initial ballot ended January 19, 2010


Attachment 7a Status of All Outstanding Interpretations



Project/Standard R # Synopsis of Issue Ballot Status Last Action Next Action to vendors who are supervised?

Project 2009‐29 TOP‐002‐2a for FMPP (Al McMeekin)

R6 Is the responsibility of a BA under R6 to plan to meet CPS and DCS under unscheduled changes in the system configuration and generation dispatch?

Initial ballot conducted and achieved a quorum and high approval: Quorum: 84.34% Approval: 84.56%

Initial ballot ended February 22, 2010.


Project 2009‐30 ― Interpretation of PRC‐001‐1 for WPSC (Al McMeekin)

R1 Seeks clarity on the use of the term “Generator Operator.”


Initial ballot ended February 26, 2010


Project 2009‐32 EOP‐003‐1 for FMPP (Al McMeekin)

R3 and R5 Do R3 and R5 apply only to automatic load shedding or both automatic and manual load shedding?

Initial ballot failed to achieve a quorum; Reballot conducted and achieved quorum and high enough approval Quorum: 91.37% Approval: 77.66%

Reballot ended March 31, 2010


2010‐INT‐01 TOP‐006‐2 for FMPP (Al McMeekin)

R1.2 and R3

Is the BA responsible for reporting generation resources available for use and TOP responsible for reporting transmission resources that are available for use? Does “appropriate technical information concerning protective relays” refer to protective relays for which the entity has responsibility

Formed ballot pool Ballot Pool closed April 5, 2010

Reopen ballot pool Post for parallel comment/ballot

2010‐INT‐02 TOP‐003‐1 for FMPP (Al McMeekin)

R2 Does the requirement to plan and coordinate for scheduled outages of system voltage regulating equipment for the Balancing Authority mean plan and coordinate scheduled outages of generators within the Balancing Authority?

Formed ballot pool Ballot Pool closed April 5, 2010


Project 2010‐INT‐03 TOP‐002‐2a for FMPP (Al McMeekin)

R2, R8, and R19

Clarity on BA obligations Formed ballot pool Ballot pool closed April 5


Project 2010‐INT‐04 EOP‐001‐1 for FMPP (Al McMeekin)

R2.4 What does “a set of plans for system restoration” mean for a Balancing Authority?

Formed ballot pool Ballot pool closed April 5


Project 2010‐INT‐05 CIP‐002‐1 for Duke Energy (Howard Gugel)

R3 Seeks clarity on the use of the term, “examples” and clarity on the use of the term, “essential”

Posted for comment September 8‐October 8, 2010

Respond to comments

RFI received on 11/4/2010 R5.3 Asks if procedural controls are an Determine if a CAN


Project/Standard R # Synopsis of Issue Ballot Status Last Action Next Action from TECO on CIP‐007 acceptable method of complying with

R5.3 when enforcement cannot be achieved through technical means, or if BOTH technical and procedural controls must be implemented in every instance

can be developed in a reasonable period of time

1

Drafting Team Vacancies

NERC currently has several drafting teams which have vacancies seeking additional subject matter experts. Participation on drafting teams provides stakeholders an excellent opportunity to become familiar with the standards development process, play a pivotal role in improving electric reliability, and interact with industry peers interested in similar issues. By submitting a nomination for a drafting team you are indicating your willingness and agreement to actively participate in the standards development process and in particular drafting team meetings if appointed to the drafting team by the Standards Committee. This means that if you are appointed to drafting team you are expected to attend the vast majority of the face-to-face drafting team meetings as well as participate in the vast majority of the drafting team meetings held via conference calls. Failure to do so shall result in your removal from the drafting team and will be a factor when considering membership for future drafting teams. The NERC coordinators working with the drafting team Chairs and Vice-chairs for the following projects have identified the need for additional subject matter experts. Industry stakeholders can nominate themselves for consideration by the Standards Committee for these specific vacancies. The Reliability Standards Development Procedure provides information on the process and drafting team participation. Any industry stakeholder meeting the indicated qualifications for the vacant appointments can submit a self nomination form to [email protected]. Please contact Monica Benson at [email protected] with questions regarding the drafting team vacancies. Drafting team vacancies are also posted on the NERC website at http://www.nerc.com/filez/standards/drafting_team_vacancies.html .

Project Vacant Appointments Qualifications

Project 2007-02 Operating Personnel Communications Protocols

Seeking an individual with physical security experience and an individual with cyber security experience to replace a team member who is retiring.

Also seeking an individual from the Eastern Interconnection to replace a team member that has retired from the team.

Also seeking an individual from the ERCOT Interconnection to replace a team member that resigned from the team.

Experience in:

developing verbal and written communications protocols for real-time operating personnel or

managing real-time bulk electric system operations.

Any member of the Reliability Coordinator Working Group (especially a member who was a principal drafter of the Alert Level Guide)

Project 2007-07 Vegetation Management

Seeking individuals from the Eastern Interconnection, WECC and Canadian

Province region to replace team members who have resigned.

Experience in:

Developing and directing vegetation management programs

Attachment 7b Drafting Team Vacancies


2

Project Vacant Appointments Qualifications

Managing real-time bulk electric system operations.

Vegetation compliance in the WECC region

Project 2007-09 Generator Verification

Seeking individual from Canada and the Generator segment.

Experience in analyzing or modeling generator equipment.

Project 2007-12 Frequency Response

Seeking individual representing Transmission Dependent Utilities (TDU).

Experience in analyzing or modeling frequency response.

Project 2008-01 — Voltage and Reactive Planning and Control

Seeking representative from a Canadian entity. Seeking individual who has

experience with reactive power planning and operational techniques in Canada.

Project 2008-12 Coordinate Interchange Standards

Seeking an individual from a Transmission Dependent Utility that is experienced with tagging, scheduling, and checking out Interchange.

Experience in managing activities associated with coordinating Interchange.

Project 2009-02 Real-time Monitoring and Analysis Capabilities

Seeking a total of three individuals from a Generator Operator, Transmission Operator, Balancing Authority, or Reliability Coordinator who is experienced in real-time operations.

Knowledge of supervisory control and data acquisition (SCADA) and Energy Management System (EMS) applications used to support real-time operations

Project 2010-13 Relay Loadability Order 733

Seeking additional candidates: At least one representative from each

of the Midwest Reliability Organization, Northeast Power Coordinating Council, and Florida Regional Coordinating Council (one candidate could potentially represent multiple regions).

At least one individual that has task involvement with the NERC Relay Loadability work or System Protection and Control Subcommittee (SPCS) generation-transmission coordination work.

Experience with the application of protective relays on generating units, generator step-up transformers, and unit auxiliary transformers across the United States and/or Canada

Items highlighted in yellow are new this month.

S - SC Report 2

S Name S - Reason for Project NERC Staff

Planned

Completio

n

Estimated

Completio

n

Percent

Complete Last Updated

S - Next Three

Meetings

Project 2006-02: Assess Transmission Future Needs Stakeholder Requestand RegulatoryDirective

Edward Dobrowolski 2/23/12 1/16/12 78% 11/29/10 None scheduled

Project 2006-04: Backup Facilities Stakeholder Requestand RegulatoryDirective

Edward Dobrowolski 1/27/11 1/25/11 95% 8/6/10 None scheduled atthis time

Project 2006-06 Reliability Coordination Stakeholder Requestand RegulatoryDirective

Stephen Crutchfield 9/16/11 9/19/11 78% 12/1/10 January 19-20, 2011- Atlanta

Project 2006-08 Transmission Loading Relief Stakeholder Requestand RegulatoryDirective

Andy Rodriquez 9/17/10 3/4/11 81% 11/19/10 None scheduled atthis time.Conference calls tobe convened asneeded.

Project 2007-01 Underfrequency Load Shedding Stakeholder Requestand RegulatoryDirective

Stephanie Monzon 3/18/11 2/2/11 96% 11/29/10

Project 2007-02 Operating PersonnelCommunication Protocols

Stakeholder Request Harry Tom 6/8/10 5/30/12 52% 11/30/10

Project 2007-03: Real-time Operations Stakeholder Requestand RegulatoryDirective

Edward Dobrowolski 1/26/12 4/5/12 72% 11/29/10 None scheduled

Project 2007-05 Balancing Authority Controls Stakeholder Requestand RegulatoryDirective

Edward Dobrowolski 3/2/11 8/3/10 100% 10/3/10 None scheduled atthis time.

Project 2007-06 System Protection Coordination Stakeholder Request Al McMeekin 3/16/11 9/8/11 69% 11/29/10

Project 2007-07 Vegetation Managment Stakeholder Requestand RegulatoryDirective

Harry Tom 10/8/10 3/22/11 52% 11/30/10 None

Project 2007-09 Generator Verification Stakeholder Requestand RegulatoryDirective

Harry Tom 6/22/12 10/19/12 38% 11/30/10 February 8-10, 2011Juno Beach FL

Project 2007-11 Disturbance Monitoring Stakeholder Requestand RegulatoryDirective

Stephanie Monzon 9/18/13 9/18/13 56% 11/29/10 December 9, 2010Web-conferenceJanuary 19-20, 2011SCE

Project 2007-12 Frequency Response Stakeholder Request Darrel Richardson 5/10/12 5/10/12 8% 11/29/10 November 2010Conference call


longm

Text Box

Attachment 7c Upcoming Project Meetings Standards Committee December 9, 2010 Agenda


Planned

Completio

n

Estimated

Completio

n

Percent


S - Next Three

Meetings

Project 2007-17 Protection System Maintenanceand Testing

Stakeholder Requestand RegulatoryDirective

Al McMeekin 4/10/12 4/10/12 55% 11/29/10 Jan 4 -6, 2011 Ft.Worth, TX - ONCOR

Project 2007-23 Violation Severity Levels Regulatory Directive Howard Gugel 12/21/10 12/7/10 98% 11/30/10

Project 2008-01 Voltage and Reactive Planning andControl


Stephen Crutchfield 12/26/12 12/21/12 47% 11/29/10 November 30, 2010(web meeting)March 15-17, 2011April 12-14, 2011May 10-12, 2011

Project 2008-06 Cyber Security Order 706 Regulatory Directive Howard Gugel 11/25/11 11/25/11 69% 11/30/10 December 14-16Tampa, FLJanuary 18-20Columbus, OHFebruary 15-17Taylor, TX

Project 2008-12 Coordinate Interchange Standards Stakeholder Requestand RegulatoryDirective

Andy Rodriquez 5/1/12 7/6/12 29% 11/19/10 November 9-10,2010 - San DiegoAdditional meetingsTBD based onprogress.

Project 2009-01 Disturbance and SabotageReporting


Stephen Crutchfield 1/27/12 1/24/12 50% 12/1/10 December 6-7, 2010- TampaJanuary 11-14, 2011- Key West

Project 2009-02: Real-time Reliability Monitoringand Analysis Capabilities

Stakeholder Request Edward Dobrowolski 12/20/13 12/20/13 20% 11/3/10 None scheduled atthis time

Project 2009-02: Real-time Reliability Monitoringand Analysis Capabilities

Stakeholder Request Edward Dobrowolski 7/3/12 7/20/12 32% 11/29/10 Week of December6th - New Orleans,LA

Project 2009-03 Emergency Operations Planning Stakeholder Requestand RegulatoryDirective

Al McMeekin 11/24/10 11/29/10 100% 11/29/10 October 26 -28, 2010Golden, CO (XcelEnergy)December 15,ReadyTalkwebconference 12-4EPTJanuary 11-13,Austin, TX TRE HQFebruary 8-10,Vancouver, BC BCHydroMarch 22-24,Washington DC,NERC HQMay 24-26,Minneapolis, MN.Xcel Energy



Planned

Completio

n

Estimated

Completio

n

Percent


S - Next Three

Meetings

Project 2010-10 FAC Order 729 Stakeholder Request Darrel Richardson 1/26/11 1/26/11 62% 11/29/10 The week ofNovember 8.

Project 2010-12 693 Directives Regulatory Directive Andy Rodriquez 9/6/10 9/9/10 100% 10/3/10 None scheduled atthis time.

Project 2010-13 Relay Loadability Order Regulatory Directive David Taylor 10/8/13 10/8/13 11% 12/1/10 TBD

Project 2010-14 Balancing Authority Reliability-based Controls


Edward Dobrowolski 12/3/12 1/31/13 1% 11/29/10 December 1 st & 2ndin Austin, TXConference call:January 5 & 6thJanuary 24 & 25 inAustin, TX
