NPCC Regional Standards Committee Preliminary Agenda--Draft … · 2020. 10. 15. · Compliance...

- 1 - LRP 3162011 922 AM

1040 Avenue of the Americas - 10th Floor New York New York 10018-3703

NPCC Regional Standards Committee Preliminary Agenda--Draft

Meeting 11-2

March 16 2011 1000 am - 500 pm March 17 2011 800 am - 1000 am

March 17 2011 1000 am - noon--Joint Meeting with the CC

Dominion Resources Services Inc Dominion Riverside Campus

Pump House Building--Second Floor 120 Tredegar Street Richmond Virginia

Dress Business Casual

RSCnpccorg Call in 719-785-1707 Guest Code 8287

1 Introductions-Agenda Review-Roster a NPCC Board of Directors approved Ben Wu (Orange and Rockland Utilities

Sector 1) and Donald Weaver (New Brunswick System Operator Sector 2) for RSC membership

2 RSC February 2011 Meeting Minute Approval and Antitrust Guidelines (in Meeting Materials Package) a

3 Action Item Assignment List and Ongoing Assignments (in Meeting Materials

Package) (Refer to Action Item Table [Item 65] at the back of Agenda) a NPCC Members on NERC Drafting Teams

- 2 - LRP 3162011 922 AM

4 Review Executive Tracking Summary (in Meeting Materials Package)

a Review entries

5 FERC (in Meeting Materials Package) a FERC Feb 17 2011 Meeting Agenda b FERC March 10 2011 Meeting Agenda Item NOPR Docket No Posted End Date When

Effective T1 Integration of Variable

Energy Resources Docket No RM10-11-000

22511 3111

T2 Fourth Quarter 2010 Compliance Filing Of The North American Electric Reliability Corporation In Response To Paragraph 629 Of Order No 693 And Request To Terminate Compliance Filing Obligation

Docket No RM06-16-000

22811

Item FERC Orders Docket No Posted Summary U1 Order Dismissing

Compliance Filing--Mandatory Reliability Standards for Critical Infrastructure Protection

RM06-22-014 31011 FERC dismisses NERCrsquos 9910 compliance filing in response to FERCrsquos 31810 Order regarding CIP Standards with respect to nuclear power plants as moot

- 3 - LRP 3162011 922 AM

6 Current and Pending Ballots (in Meeting Materials Package)

a

b

7 Overlapping Postings (in Meeting Materials Package)

a

8 Join Ballot Pools (in Meeting Materials Package)

a

9 Posted for Comment (in Meeting Materials Package)

a

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

Concept White Paper Comment Form (link to Word Version) Announcement

Comment Form 21611 4411

b Notice of proposed Changes to RFC Rules of

Procedure and Request for Comments

Comments-- Electronic submission to ropcommentsnercnet

3111 41511

c Proposed Amendments to NERC Rules of Procedure Appendices 3B and 3D


3111 41511

d

Project 2010-07 - Generator Requirements at the Transmission Interface - Various BAL CIP EOP FAC IRO MOD PER PRC TOP and VAR standards

White Paper Attachment 1 Attachment 2 Announcement

Informal Comment Period--Click on Submit

Comments--Comments to be sent to

Malloryhugginsnercnet

3411 4411

- 4 - LRP 3162011 922 AM

e

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

EOP-004-2 Redline to last posted Comment Form (link to Word Version) Implementation Plan CIP-001-1 EOP-004-1 Announcement


Item 9a--Will not make NERCrsquos active project list 10 Reference Documents Posted For Comment

a

11 Concluded Ballots (in Meeting Materials Package) httpsstandardsnercnetBallotsaspx

(clicking in the column to the right of ldquoBallot Periodsrdquo column links to the Ballot Results)

Results of Ballot

RSC RecommendDate

a Project 2010-11 - TPL Table 1

Footnote B Recirculation

Ballot 12611 2511

Quorum 9361

Approval 8654

Yes 1511

b Project 2007-07 - Vegetation

Management - FAC-003

Successive Ballot and

Non-Binding Poll

21811 22811

Quorum 7928

Approval 7934

Yes 22211

c

Project 2006-06 - Reliability Coordination - COM-001 COM-002 IRO-001 and IRO-014

Initial Ballot 22511 3711

Quorum 8710

Approval 4954

Yes 3211

d Project 2007-23 - Violation

Severity Levels Non-binding

Poll 2911 21811

Ballot Pool 310

Opinions 141

Yes 102810

72 Support

- 5 - LRP 3162011 922 AM

e Project 2010-13 - Relay Loadability

Order - PRC-023


Non-Binding Poll

12411 21311

Quorum 8395

Approval 6571

Yes 21111

f Project 2010-13 - Relay Loadability Order - PRC-023

Recirculation Ballot

22411 3611

Quorum 8735

Approval 6883

Yes 21111

12 Posted For 30-Day Pre-Ballot Review (Open Ballot Pools) Between RSC

Meetings

a

13 Concluded Comment Forms (in Meeting Materials Package)

a Standards Project Prioritization Reference Document and Tool

Comment Form

12111 21011

b Project 2007-12 - Frequency Response Comment

Form 2411 3711

c Project 2007-07 - Vegetation Management - FAC-003 Comment Form

12711 22811

d Project 2007-23 - Violation Severity Levels Comment

Form 12011 21811

e Project 2006-06 - Reliability Coordination - COM-001

COM-002 IRO-001 and IRO-014 Comment

Form 11811 3711

f Regional Reliability Standards - PRC-006-NPCC-1 -

Automatic Underfrequency Load Shedding

Comment Form

(no comments submitted)

11011 22411

g CAN-0015--Draft CAN-0015 Unavailability of NERC Tools Comments 2411 21811

h CAN-0016--Draft CAN-0016 CIP-001-1 R1 - Applicability to Non-BES

Comments 2411 21811

i CAN-0017--Draft CAN-0017 CIP-007 R5 System Access

and Password Controld Comments 21111 3411

j CAN-0018--Draft CAN-0018 FAC-008 R121 - Terminal

Equipment Comments 2411 21811

k Proposed Changes to Rules of Procedure to Add Section

1700 - Challenges to Determinations Comments 21411 3711

- 6 - LRP 3162011 922 AM

14 Reference Documents Posted For Comment Between RSC Meetings

a

15 Drafting Team Nominations Open (Current and between RSC Meetings)

a

16 NERC Meetings (in Meeting Materials Package) a ERO-RAPA b MRC and BOT Meetings

1 Member Representatives Committee and Board of Trustees Meeting Feb 16-17 2011

2 Board of Trustees Conference Call March 10 2011 a The NERC 2011-2013 Workplan with the prioritized standards b The PRC-023-1 Standard (Relay Loadability) Phase 1 due to FERC

by March 16 2011 c The VSLs for the CIP Version 4 d A set of VSLs for various other standards

e The NERC filing in response to the FERC performance assessment was reviewed discussed and approved as an Informational filing for FERC due date for filing is March 18 2011

17 NERC RSG RRSWG (in Meeting Materials Package) a RSG Feb 14 2011 Conference Call agenda b RSG March 15 2011 Conference Call agenda

18 Standards Committee Report (in Meeting Materials Package) a Two Standards Committee Positions open Nominations closed March 8

2011 b Ballot results of the Standards Committee E-mail ballot of the proposed

Reliability Standards Development Plan 2011-2013 c Notes March 10 2011 Standards Committee Meeting 19 SCPS Meeting a SDT selection criteria 20 NERC Compliance Application Notices a Comments to the CAN process

21 NERC Bulk Electric System Definition (in Meeting Materials Package) a Drafting Team members b NERC Staff Comments on Bulk Electric System (BES) Concept

Document c Drafting Team meetings 1 March 2-4 2011 meeting

- 7 - LRP 3162011 922 AM

d Summary of Definition of BES Drafting Team meetings sent to the NPCC Board of Directors

1 Feb 9-11 2011 2 March 2-4 2011 e Work of the RBESDCG f Brian Evans-Mongeon presentationdiscussion

22 NPCC Regional Standards--Update (in Meeting Materials Package)

a Disturbance Monitoring (PRC-002-NPCC-01) 1 VSLs approved by NPCC membership NERC Board of Trustees

approved Nov 4 2010 Being prepared for FERC and Canadian Provincial authority filings

b Underfrequency Load Shedding 1 Regional Standard Drafting Team has responded to all comments

received in the 2nd Open Process Posting TFSS has recommended RCC endorsement for RSC approval of a 30 day pre-ballot review

a Ten day ballot concluded on Jan 28 2011 Did not get quorum RSC remanded back to Drafting Team

b Drafting Team Meeting scheduled for March 21-22 2011 at the NPCC Offices to answer comments received to the NERC posting and address outstanding issues

c Special Protection System d Regional Reserve Sharing 1 Draft RSAR developed 2 TFCO soliciting for Drafting Team members

23 NY adoption of more stringentspecific NPCC Criteria

a Status of the filing 24 Directory and Regional Work Plan Status

a Directory effective dates Directory Number

Title Lead Group Status

Current Activity

1 (A-2) Design and Operation of the Bulk Power System

Approved on 1212009

TFCP has charged CP11 with a comprehensive review of Directory 1 to include the triennial document review an examination of the NERC TPL standards the existing NPCC planning criteria and the implementation of Phase 2 of the Directory Project which will reformat existing Directory criteria into NERC style requirements CP11 received additional direction and feedback from TFCP at the February 2011 TFCP meeting CP11rsquos schedule calls for presenting a final draft to RCC in November 2011

2 (A-3) Emergency Operation

Approved on 102108

Automatic UFLS language transferred to Directory 12 Next TFCO review Oct 21 2011

- 8 - LRP 3162011 922 AM

3 (A-4) Maintenance Criteria for BPS Protection

Approved on 71108

TFSP review underway

4 (A-5) Bulk Power System Protection Criteria

Approved on 12109


5 (A-6) Operating Reserve

TFCO Directory5 was approved by the Full Members on December 2 2010 TFCO working to resolve outstanding reserve issues associated with Directory 5 TFCO expects to post a revised version of Directory 5 to the Open Process this spring

6 New Reserve Sharing

TFCO TFCO considering draft of a new Directory on Regional Reserve Sharing which would replace C38 until a Regional Standard is developed TFCO expects to psot draft of Directory 6 this spring

7 (A-11)

Special Protection Systems

Approved on 122707

TFSP currently reviewing Directory 7 in accordance with the NPCC Reliability Assessment Program TFCP and TFSS will agree on revisions to the SPS approval and retirement and send any proposed changes to TFSP

8 (A-12)

System Restoration

Approved on 102108

TFCO made revisions to criteria for battery testing in October 2010 Next review date July 9 2012

9 (A-13)

Verification of Generator Real Power Capability

Approved on 122208

Directories 9 and 10 have been identified to be reformatted in accordance with Phase 2 of the Directory Project Additionally TFCO to incorporate draft language that would revise section 70 to ensure that documentation is not sent to TFCO The next TFCO review is scheduled for July 2012

10(A14) Verification of Generator Reactive Power Capability

Approved on 122208

Refer to Directory 9 preceding

12 UFLS Program Requirements

Approved on 62609

Small entity (less than 100MW) revision approved by Full Members on 332010 The RCC approved one additional year for Quebec to complete UFLS implementation (Quebec implementation term is now three years) Open Process posting concluded on Jan 21 2011 that considered revisions to the UFLS Implementation Plan

- 9 - LRP 3162011 922 AM

25 Review RFC MRO Standards Relevant to NPCC (in Meeting Materials

Package) a RFC Standards Under Development webpage

httpsrsvprfirstorgdefaultaspx b RFC Standard Voting Process (RSVP) webpage ReliabilityFirst Corporation - Reliability Standards Voting Process MOD-025-RFC-01 - Verification and Data Reporting of Generator Gross

and Net Reactive Power Capability passed its 15 day Category vote and was approved by the RFC Board of Directors at their March 3 2011 Meeting

Standard Under

Development Status Start Date End Date

1

2

c Midwest Reliability Organization Approved Standards

httpwwwmidwestreliabilityorgSTA_approved_mro_standardshtml (click on RSVP under the MRO header)

d Midwest Reliability Organization Reliability Standard Voting Process webpage (table lists standards under development) Midwest Reliability Organization - Reliability Standards Voting Process

e As of June 14 2010 MRO suspended its regional standards development

26 Report on NERC NAESB and Regional Activities (in Meeting Materials

Package) a Report on NERC NAESB and Regional Activities 1 Jan 31 2011 2 Feb 28 2011

27 Task Force Assignments

Standard Under Development Status Start Date End Date

1 PRC-006-MRO-01 - Underfrequency Load Shedding Requirements (see e below)

Was posted for second 30 day

comment period 51910 - 61710

2

- 10 - LRP 3162011 922 AM

28 Future Meetings and Other Issues (in Meeting Materials Package)

a Department of Energy Launches Cyber Security Initiative b FERC Cybersecurity Efforts c Severe Impact Resilience Task Force (SIRTF) formed d Remarks of Gerry Cauley to the House Armed Services Committee

Subcommittee on Emerging Threats and Capabilities e NERC Critical Infrastructure Protection Committee Dec 8-9 2010

Meeting Minutes f Draft for Comment NPCC Board Minutes 2-8-11 Meeting and NERC MRC

and BOT Summary Notes g Draft 7 of SERC Underfrequency Load Shedding Standard Posted for

Comments Due March 24 2011 h SPP RE UFLS Regional Standard- Balloting Results-Proposed Standard

Fails i CIP implementation questions

j Cyber Attack Task Force Formed as Part of Coordinated Action Plan k Presentations from the 2011 NARUC Winter Committee Meetings httpwwwnarucorgmeetingpresentationscfm92 l NERC Operating Committee March 8-9 2011 Meeting--notes m NERC Planning Committee March 8-9 2011 Meeting--notes

RSC 2011 Meeting Dates

May 18-19 2011 Saratoga New York

October 19-20 2011 Boston Massachusetts

August 3-4 2011 Montreal Quebec

Nov 30 - Dec 1 2011 Toronto Ontario

2011 RSC Conference Call Schedule (call 212-840-1070--ask for the RSC [Guyrsquos or Leersquos] Conference Call)

April 1 2011 August 19 2011 April 15 2011 Sept 2 2011 April 29 2011 Sept 16 2011 May 13 2011 Sept 30 2011 June 3 2011 Oct 28 2011 June 17 2011 Nov 10 2011 (Thursday) July 1 2011 Dec 16 2011 July 15 2011 Dec 30 2011

- 11 - LRP 3162011 922 AM

BOD 2011 Meeting Dates

May 3 2011 Teleconference September 20 2011 NPCC June 30 2011 NPCC October 26 2011 Teleconference

July 28 2011 Teleconference November 30 2011 Toronto

RCC CC and Task Force Meeting Dates--2011

RCC June 1 Sept 8 Nov 29 CC April 13 May 16 June 14-15 July 13

August 17 Sept 21-22 Oct 19 Nov 16 Dec 13-15

TFSS TFCP May 11 August 17 Nov 2 TFCO April 14-15 August 11-12 Oct 6-7 TFIST TFSP March 22-24 May 24-26 July 19-21

Sept 27-29 Nov 15-17

- 12 - LRP 3162011 922 AM

Joint Meeting With CC

1 Directory Revision Schedule 2 NPCC Compliance Schedule for 2011 and 2012 3 CCRSC Involvement with Review of Directories 4 Directory Format to clearly identify more Stringent NPCC Criteria 5 CANs enforcement 6 Transformation of the NPCC Directories and other Criteria Documents that

support the non-approved NERC fill-in-the blank standards into Regional Reliability Standards

Examples

Directory 1MOD-11 amp MOD-13

Directory 12 PRC-006 (Continent Wide UFLS once approved) and the presently approved PRC-007 (to be retired by Project 2007-1)

Directory 9 MOD-024-1

Directory 10MOD-025-1

7 Original intent of FERC Order 693 was for NERCRegions to produce Regional Standards to replace-fill-in-the-blank standards

8 Status of Standard PRC-006-NPCC-1 Automatic Underfrequency Load Shedding

9 Progress on the proposed revisions for Directory 12 and the proposed revisions to the Directory 12 Implementation Plan approved by TFSS

10 The Policy of continued use of NPCC Task Forces in the development of new Criteria in the present timeframe in which NERC is accelerating its roll out of more stringent enforceable Standards

Example - Proposed PRC-005-2 and Directory 3 - Is a more specific or more stringent protection system maintenance really needed within NPCC

Respectfully Submitted Guy V Zito Chair RSC Assistant Vice President-Standards

- 13 - LRP 3162011 922 AM

Northeast Power Coordinating Council Inc

Northeast Power Coordinating Council Inc (NPCC)

Antitrust Compliance Guidelines

It is NPCCrsquos policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably restrains competition The antitrust laws make it important that meeting participants avoid discussion of topics that could result in charges of anti-competitive behavior including restraint of trade and conspiracies to monopolize unfair or deceptive business acts or practices price discrimination division of markets allocation of production imposition of boycotts exclusive dealing arrangements and any other activity that unreasonably restrains competition It is the responsibility of every NPCC participant and employee who may in any way affect NPCCrsquos compliance with the antitrust laws to carry out this commitment Participants in NPCC activities (including those participating in its committees task forces and subgroups) should refrain from discussing the following throughout any meeting or during any breaks (including NPCC meetings conference calls and informal discussions)

bull Industry-related topics considered sensitive or market intelligence in nature that are outside of their committeersquos scope or assignment or the published agenda for the meeting

bull Their companyrsquos prices for products or services or prices charged by their competitors

bull Costs discounts terms of sale profit margins or anything else that might affect prices

bull The resale prices their customers should charge for products they sell them bull Allocating markets customers territories or products with their competitors bull Limiting production bull Whether or not to deal with any company and bull Any competitively sensitive information concerning their company or a

competitor

Any decisions or actions by NPCC as a result of such meetings will only be taken in the interest of promoting and maintaining the reliability and adequacy of the bulk power system Any NPCC meeting participant or employee who is uncertain about the legal ramifications of a particular course of conduct or who has doubts or concerns about whether NPCCrsquos antitrust compliance policy is implicated in any situation should call NPCCrsquos Secretary Andrianne S Payson at 212-259-8218

- 14 - LRP 3162011 922 AM

Action Item List

Action Item

Number

Agenda Item

Number Description Owner Due Status

32 16b To discuss with Herbert Schrayshuen how HQ because of its unique operational requirements will be addressed in standards development

Guy Zito--member of Standards Committee Process Subcommittee

RSC Meeting

Ongoing as of 21010 Sylvain

Clermont and David Kiguel

working with Guy Zito Herbert Schrayshuen

replaced Gerry Adamski at NERC

The new NERC management team

will have to be made familiar with

this item August 20-21 2008

Feb 17-18 2009

June 17-18 2009

August 6-7 2009

60 3a NPCC representatives from NERC drafting teams that have documents posted for comments report at RSC Meetings

Lee Pedowicz RSC Meeting

Ongoing

61 21 Notify NPCC Drafting Team members that the RSC is available for advice at any time


Ongoing

- 15 - LRP 3162011 922 AM

Action Item

Number

Agenda Item


and that they will be invited to call in with status reports

Sept 24-25 2009

Nov 4-5 2009

April 21-22 2010

63 ---- Coordination with the Compliance Committee to develop Joint Activity Action List

Greg Campoli RSC Meeting

Outgrowth of RSCCC joint

session April 21 2010 Ongoing Joint RSCCC Meeting this

meeting Ralph Rufrano rejoined the RSC in the

capacity of NPCC Compliance liaison Comments not to be

submitted on the CCEP

June 29-30 2010

65 ---- RSC to review the

NPCC Members on NERC Drafting Teams list Saurabh Saksena to maintain Will get input from Carol Sedewitz

RSC RSC Meeting

Ongoing

August 18-19 2010

- 16 - LRP 3162011 922 AM

Action Item

Number

Agenda Item


66 ---- Status of Memorandum of Understanding

Si-Truc Phan RSC Meeting

Provide update

67 ---- Effectively communicating to the RSC

Guy Zito Lee Pedowicz Michael Lombardi Saurabh Saksena Kurtis Chong Sylvain Clermont

RSC Meeting

Achieve RSC consensus

Nov 30 2010 Dec 2 2010

68 ---- Revise Regional Reliability Standards Development Procedure


RSC Meeting

Initial draft with revisions made

69 ---- Revise RSC Scope RSC RSC Meeting

Feb 2-3 2011

70 20 Talk to Stan Kopman and the CC about the process for submitting comments after Valerie Agnew (NERC) drafts CANs for their first posting Industry will have two weeks for comments

Guy Zito Lee Pedowicz

RSC Meeting

71 ---- Talk to Compliance about Reliability Standard RSAWs

Guy Zito RSC Meeting

- 17 - LRP 3162011 922 AM

Action Item

Number

Agenda Item


There should be a Compliance Committee representative on the Drafting Team

72 ---- Find out what other Regions are doing regarding interpretations


73 ---- Discuss consistency with the RSG



Regional Reliability Standards Development Procedure Process Manual

Approved by NPCC Board of Directors September 19 2007

Approved by NERC BOT October 23 2007 Adopted by FERC March 21 2008

1

NPCC

REGIONAL RELIABILITY STANDARDS DEVELOPMENT PROCEDUREPROCESS MANUAL

TABLE OF CONTENTS

NO TABLE OF CONTENTS ENTRIES FOUNDERROR NO TABLE OF CONTENTS ENTRIES FOUNDI EXECUTIVE SUMMARY 2

II REGIONAL RELIABILITY STANDARD DEVELOPMENT PROCEDURE 1 CHARACTERISTIC ATTRIBUTES 2 2 ELEMENTS OF A REGIONAL STANDARD 5 3 TERMS AND FUNCTIONS 8 4 PROCEDURE DESCRIPTION 10 5 FLOWCHART 15 6 ERO AND REGULATORY APPROVALS 16

7 APPEALS 16 III APPENDIX

A) RSAR FORM 19

2

Formatted Indent Left 0 Hanging 025Numbered + Level 1 + Numbering Style I IIIII hellip + Start at 1 + Alignment Left + Alignedat 025 + Indent at 075

3

I I EXECUTIVE SUMMARY The purpose of the Northeast Power Coordinating Council Inc (NPCC) is to enhance the reliability of the international interconnected bulk power system in Northeastern North America through the development of more stringent and specific regional reliability standards and compliance assessment and enforcement of continent-wide and regional reliability standards pursuant to the execution and implementation of a Regional Delegation Agreement with the Electric Reliability Organization (ERO) and applicable Canadian Memoranda of Understanding that are backstopped by the Federal Energy Regulatory Commission (FERC) and Canadian Provincial authorities In the development and enforcement of Regional Reliability Standards NPCC to the extent possible facilitates attainment of fair effective efficient and competitive electric markets

General Membership in NPCC is voluntary and is open to any person or entity including any entity participating in the Registered Ballot Body of the ERO that has an interest in the reliable operation of the Northeastern North American bulk power system

The This NPCC Regional Reliability Standards Development ProcedureProcess Manual describes the procedures policies and practices approved by NPCC members and implemented to ensure an ldquoopen fair and inclusiverdquo process for the transparent initiation development implementation and revision of NPCC Rregional Rreliability Sstandards (regional standards) necessary for the reliable operation of the international and interconnected bulk power system in Northeast North America These Sstandards will in all cases not be inconsistent with or less stringent than any requirements of the North American Electric Reliability CouncilElectric Reliability Organization (NERCERO) Reliability Standards The procedure will not unnecessarily delay the development of the proposed reliability standards Each regional reliability standard shall enable or support one or more of the-NERCERO reliability principles1

II REGIONAL RELIABILITY STANDARD DEVELOPMENT PROCEDUREPROCESS MANUAL

thereby ensuring that each standard serves a purpose in support of the reliability of the regional bulk power system Each standard shall also be consistent with all of pertinent reliability principles and criteria thereby ensuring that no standard undermines reliability through as an unintended consequence

The NPCC Regional Reliability Standards Development ProcedureProcess Manual is

1 CHARACTERISTIC ATTRIBUTES

bull Open mdash The NPCC Regional Reliability Standards Development ProcedureProcess Manual provides any person the ability to participate in the development of a standard Anyor entity that is directly and materially affected by the reliability of the NPCCrsquos bulk power system has the ability to participate in the development and approval of reliability standards NPCC

1 Available on the NERC website wwwnerccom

Comment [kbc1] Very longwindede COnsider revising

Comment [kbc2] See general note about consistency in the text box at the end of the document and make appropriate changes throughout the document if agree with this approach

Comment [kbc3] Why do we need this Consider deleting

Formatted Indent Left 0 Hanging 025

Comment [kbc4] Dont agree with change This manual describes the process

Formatted Indent Left 025 Hanging 025 Dont adjust space between Latin andAsian text

Comment [kbc5] Dont agree the manual describes the process so changed to Process

Comment [kbc6] Some repetition revised to remove

Formatted English (Canada)

4

utilizes a website to accomplish this Online posting and review of standards and the real time sharing of comments uploaded to the website allow complete transparency There are no undue financial barriers to participation Participation in the open comment process is not conditional upon membership in the ERO NPCC or any organization and participation is not unreasonably restricted on the basis of technical qualifications or other such requirements There are no undue financial barriers to participationNPCC utilizes a website to accomplish this Online posting and review of standards and the real time sharing of comments uploaded to the website allow complete transparency

bull Inclusive mdash The NPCC Regional Reliability Standards Development ProcedureProcess Manual provides any person with a direct and material interest the right to participate by expressing an opinion and its basis have that position considered and in the event they are not satisfied with the response to their opinion appealed the response through an established appeals process if adversely affecteddesired

bull Balanced mdash The NPCC Regional Reliability Standards Development ProcedureProcess Manual has seeks to achieve a balance of interests and all those entities that are directly and materially affected by the reliability of the NPCCrsquos bulk power system are welcome to participate and shall not be dominated by any two interest categories and no single interest category shall be able to defeat a matter This will be accomplished through the NPCC Bylaws 2

bull Fair Due Process mdash The NPCC Regional Reliability Standards Development ProcedureProcess Manual provides for reasonable notice and opportunity for public comment The procedure includes public notice of the intent to develop a standard a 45 calendar day public comment period on the proposed standard request or standard with due consideration of those public comments and responses to those comments will to be posted on the NPCC website A final draft of the notice of intent to develop the standard or the draft standard itself will be posted for a 30 calendar day pre-balloting period and thenafter which a ballot of NPCC Members will be conducted Upon approval by the NPCC Members the NPCC Board then votes to approve submittal of the Regional Reliability Standard to NERC

which defineing eight six sectors (categories) for voting All individuals and entities that are directly and materially affected by the reliability of the NPCCrsquos bulk power system are welcome to participate

bull Transparent mdash All actions material to the development of Regional Reliability Standards are transparent and information regarding the progress of a standards development action is made available to the public through postingsed on the NPCC website as well as through extensive email lists

In as much as NPCC is one of several regional entities within the Eastern Interconnection of North America there will be no presumption of validity by the ERO for any NPCC Regional Reliability Standard In order to receive the approval of

2 Available on the NPCC website wwwnpccorg

Comment [kbc7] Moved for better flow of ideas

Comment [kbc8] Vague and perhaps not needed unless there is some legal angle to this consider removing

Comment [kbc9] Needed


Comment [kbc11] Change to process

Comment [kbc12] The appellant need not be adversely affected must they


Comment [kbc14] We recall that the number of sectors is to be reduced from 8 to 6 Please confirm If Bylaws will not be amended to reflect this before themanual is approved leave as 8 and revise later


Formatted Indent Left 025

Field Code Changed


5

the ERO the NPCC Reliability Standards Development Process must also achieve the following objectives

bull No Adverse Impact on Reliability of the Interconnection mdash An NPCC

Regional Reliability Standard provides a level of bulk power system reliability that is necessary and adequate to protect public health safety welfare and North American security and will not have an adverse impact on the reliability of the Interconnection or other Regions within the Interconnection

bull Justifiable Difference mdash An NPCC Regional Reliability Standard is based

on justifiable differences between Regions such as different electrical systems or facilities sensitivity of load to disruptions sensitivity of generation to disruptions frequency and voltage sensitivity system operating limit development and facilities ratings process electrical system interactions etc

bull Uniformity- mdash NPCC Regional Reliability Standards shall provide for as

much uniformity as possible with reliability standards across the interconnected bulk power system of the North American continent A NPCC Reliability Standard shall be more stringent than a continent-wide reliability standard may include a regional variation that addresses matters that the continent-wide reliability standard does not or shall be a regional difference necessitated by a physical difference in the northeastrsquos bulk power system3

where the interpretation of the phrase ldquophysical differencerdquo will be consistent with FERCrsquos Order issued September 22 2004 Granting Request For Clarification regarding Docket No PL04-5-000 Policy Statement on Matters Related to Bulk Power System Reliability

bull No Undue Adverse Impact on Commerce mdash An NPCC Regional Reliability Standard will not cause any undue adverse impact on business activities that are not necessary for reliability of the Region and its interconnected Regions All regional reliability standards shall be consistent with NERCrsquos market principles4

Other Attributes provisions of the NPCC Regional Reliability Standards Development ProcedureProcess Manual include

bull Maintenance of Regional Reliability Standards - NPCC Regional

Reliability Standards will be reviewed for possible revision at least every three years after FERC approval and follow the same process as in the case of a new standard If no changes are warranted the Regional Standards Committee (RSC) shall recommend to the NPCC Board that the standard be reaffirmed If the review indicates a need to revise or withdraw a standard a Regional Standard Authorization Request shall be prepared by the RSC and submitted in accordance with the NPCC Regional Reliability Standards Process The old

3 The interpretation of the phrase ldquophysical differencerdquo will be consistent with FERCrsquos Order issued

September 22 2004 Granting Request For Clarification regarding Docket No PL04-5-000 Policy Statement on Matters Related to Bulk Power System Reliability


Formatted Highlight

Comment [kbc16] There are two ways to approach using the indefinite article when placed in from of an acronym We just need to be consistent throughout the document I have flagged the cases I have seen

Formatted Highlight

Formatted Highlight

Comment [kbc17] Very unwieldy We have made this a footnote

Formatted Highlight

Formatted Font Not Bold




Comment [kbc18] We recommend moving this entire section and inserting it after the process for developing a new standard is described That way all of the players involved would have been described as well as the process for developing the new standard Also each of these three items should be placed in a separate section and written as a process with a flowchart included for each as necessary These changes should help to minimize some of the repetition that exists in the document as currently structured

Comment [kbc19] By whom See general comments in the text box on page 2

Comment [kbc20] From FERC (and Canadian Authority) approval or from NERC BOT approval Need to make this clear so a date can be clearly defined Since there can be

Comment [kbc21] Moved for better sequencing

Formatted Indent Left 0 Hanging 013Space After 6 pt



6

existing approved standard subject to revision will remain in place effect until such time as the revised version has received FERC or applicable Canadian Regulatory Authority approvals as appropriate passed through the entire process at which point the old standard it will be retired in accordance with any applicable new implementation plan associated with the newly approved regional revised standard The review process shall be conducted by soliciting comments from the stakeholders and through open posting on the NPCC website If no changes are warranted Regional Standards Committee (RSC) shall recommend to the NPCC Board that the standard be reaffirmed If the review indicates a need to revise or withdraw a standard a regional standard authorization request shall be prepared by the RSC and submitted in accordance with the standards development process contained in this procedure

bull Maintenance of the Regional Reliability Standards Development

ProcedureProcess Manual - This NPCC Regional Reliability Standards Development ProcedureProcess Manual will be reviewed for possible revision at least once every five years or more frequently if needed and subject to the same procedure as that ofapplies to the development of a regional standard All such revisions shall be subject to approval by the NPCC Board NERC FERC and could be subject to approval if required by applicable authorities in Canada The NPCC RSC has the authority to make non-substantive changes to this procedure and subsequently notify the NPCC Board for their concurrence at the Boardrsquosir next scheduled meeting

bull Interpretation of Standards - All persons who are directly and materially

affected by the NPCCrsquos bulk power system reliability shall be permitted to request an interpretation of an NPCC regional reliability standard The person requesting an interpretation will shall send an email request to the Regional Standards Process Manager (RSPMManager of Reliability Standards) as noted on the NPCC website explaining the specific circumstances surrounding the request and what clarifications are required as applied to those circumstances The request should shall indicate the material impact to the requesting party or others caused by the lack of clarity or a possibly incorrect interpretation of the regional standard The RSPMManager of Reliability Standards along with guidance from the RSC will forward the request to the originating Task Force to whom responsibility was originally assigned for which acted as the drafting team for that regional reliability standard The Task Force will address through a written response the request for clarification as soon as practical but not more than 45 business days from its receipt by the Task Force This written interpretation will be posted along with the final approved and adopted regional standard and will stand until such time as the regional standard is revised through the normal RSAR process at which time the regional standard will be modified to incorporate the clarifications provided by the interpretation

2 ELEMENTS OF A RELIABILITY STANDARD

bull Elements of a Regional Reliability Standard

Comment [kbc22] When does the process come to an end After FERC or NERC BOT this gives the impression that after NERC BOT adoption the standard will become effective Better to say after FERC or applicable Canadian Regulatory approvals or something similar

Comment [kbc23] Not strictly necessary since weve already said above that well be following the same process as for a new standard Reinstate if deemed necessary

Comment [kbc24] From when FERC date

Comment [kbc25] Too much detail since this will be repeated in Section 4 Prune this down

Formatted Highlight

Formatted Highlight

Comment [kbc26] why specify

Comment [kbc27] Stronger

Comment [kbc28] Should there be a step here for RSC or MRS review

7

To ensure uniformity of regional reliability standards and notavoid inconsistentcy with NERC continent-wide standards a regional reliability standard shall consist of the elements identified in this section of the procedure These elements are intended to apply a systematic discipline in the development and revision of regional standards This discipline is necessary to for achieving regional standards that are measurable enforceable and consistent as well as results-oriented56

ie

Performance-based Risk-based and CompetencyCapability-based

as well as being measurable enforceable and consistent The Standard Drafting Team (SDT) should strive to achieve a portfolio of performance risk and competencycapability-based mandatory reliability requirements that support an effective defense-in-depth strategy Each requirement should identify a clear and measurable expected outcome such as a) a stated level of reliability performance b) a reduction in a specified reliability risk or c) a necessary competency a) Performance-based - defines a specific reliability objective or outcome that has a direct observable effect on the reliability of the bulk power system ie an effect that can be measured using power system data or trendsdefines a particular reliability objective or outcome to be achieved In its simplest form a results-based requirement has four components who under what conditions (if any) shall perform what action to achieve what particular result or outcome b) Risk-based - defines actions of entities that reduce a stated risk to the reliability of the bulk power system and can be measured by evaluating a particular product or outcome resulting from the required actionspreventive requirements to reduce the risks of failure to acceptable tolerance levels A risk-based reliability requirement should be framed as who under what conditions (if any) shall perform what action to achieve what particular result or outcome that reduces a stated risk to the reliability of the bulk power system c) CompetencyCapability-based - defines capabilities needed to perform reliability functions and can be measured by demonstrating that the capability exists as requireddefines a minimum set of capabilities an entity needs to have to demonstrate it is able to perform its designated reliability functions A competency-based reliability requirement should be framed as who under what conditions (if any) shall have what capability to achieve what particular result or outcome to perform an action to achieve a result or outcome or to reduce a risk to the reliability of the bulk power system All mandatory requirements of a regional reliability standard shall be within the standard document Supporting documents to aid in the implementation of

5 Results-based Standards see httpwwwnerccomfilezstandardsProject2010-06_Results-

based_Reliability_Standardshtml 6 Results-based Standards presentation see httpwwwnerccomfilesResults-Based-Standards-

102010pdf

Formatted Superscript

Formatted Bulleted + Level 3 + Aligned at 125 + Tab after 15 + Indent at 15

Formatted Indent Left 075 First line 0


Comment [kbc29] See consistency comment in text box

Comment [kbc30] Need something stronger or more definitive


8

a standard may be referenced by the standard but are not part of the standard itself The most current version of the approved NERC Reliability Standard template and its associated elements as or if applicable will be used at the time of the development of the NPCC Regional Reliability Standard to ensure all essential elements are contained therein to achieve consistency and uniformity and meet all statutory requirements A sample of the elements contained in the standard appears in Table 1 below however the latest ERO Board approved Standard template that may be found on the NERC website will supersede the list below at the time the regional standard is developed

Each regional reliability standard shouldshall enable or support one or more of the reliability principles as identified in the most recent set posted on the NERC website (see below) Each reliability standard shouldshall also be consistent with all of the reliability principles The intent of the set of NPCC regional reliability standards is to deliver an Adequate Level of Reliability as defined by NERC

a) 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 and Regional Reliability Standards Directories and Criteria

b) 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

c) 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

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

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

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

g) The reliability of the interconnected bulk power systems shall be assessed monitored and maintained on a wide-area basis

h) Bulk power systems shall be protected from malicious physical or cyber attacks

Recognizing that bulk power system reliability and electricity markets are inseparable and mutually interdependent all regional reliability standards shall be


Formatted Indent Left 125 SpaceBefore 12 pt

Formatted Space Before 12 pt

9

consistent with the most recent set of mMarket iInterface pPrinciples as posted on the NERC website Consideration of the mMarket iInterface pPrinciples is intended to ensure that regional reliability standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets Elements of a Regional Reliability Standard A regional reliability standard includes several components designed to work collectively to identify what entities must do to meet their reliability-related obligations as an owner operator or user of the bulk power system The components of a regional reliability standard include mandatory and enforceable sections and informational sections of the standard Mandatory and Enforceable Sections of a Standard Title A brief descriptive phrase identifying the topic of the standard Number A unique identification number assigned in accordance with a published classification system to facilitate tracking and reference to the standards Purpose The reliability outcome achieved through compliance with the requirements of the standard Applicability Effective Dates Identification of when each requirement becomes effective in each jurisdiction Requirement An explicit statement that identifies the functional entity responsible the action or outcome that must be achieved any conditions achieving the action or outcome and the reliability-related benefit of the action or outcome Each requirement shall be a statement for which compliance is mandatory Measure Provides identification of the evidence or types of evidence needed to demonstrate compliance with the associated requirement Each requirement shall have at least one measure Each measure shall clearly refer to the requirement(s) to which it applies Evidence Retention Identification for each requirement in the standard of the entity that is responsible for retaining evidence to demonstrate compliance and the duration for retention of that evidence Variance A requirement (to be applied in the place of the continent-wide requirement) and its associated measure and compliance information that is applicable to a specific geographic area or to a specific set of functional entities Informational Sections of a Standard Application Guidelines Guidelines to support the implementation of the associated standard Procedures Procedures to support implementation of the associated standard Time Horizon The time period an entity has to mitigate an instance of violating the associated requirement4 Compliance Enforcement Authority The entity that is responsible for assessing performance or outcomes to determine if an entity is compliant with the associated standard

Comment [kbc31] Are these Market Interface Principles general enough that they apply to Canadian markets Can we include language to cater for Canadian market principles

Comment [kbc32] This looks like a cut and paste from the NERC Standards Process Manual so no editing done here Major reformatting is required

Comment [kbc33] Is this the end of the mandatory and enforceable section Heading required to indicated informationand a compliance section

10

Compliance Monitoring and Assessment Processes Identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated standard Additional Compliance Information Any other information related to assessing compliance such as the criteria or periodicity for filing specific reports Compliance Elements Associated with a Standard Violation Risk Factors and Violation Severity Levels Violation risk factors (VRFs) and violation severity levels (VSLs) are used as factors when determining the size of a penalty or sanction associated with the violation of a requirement in an approved reliability standard5 Each requirement in each reliabilityregional standard has an associated VRF and a set of VSLs VRFs and VSLs are developed by the drafting team working with NERCNPCC staff at the same time as the associated regional reliability standard but are not part of the reliabilityregional standard The NPCC Board of TrusteesDirectors is responsible for approving VRFs and VSLs Violation Risk Factors VRFs identify the potential reliability significance of non-compliance with each requirement Each requirement is assigned a VRF in accordance with the latest approved set of VRF criteria6 Violation Severity Levels VSLs define the degree to which compliance with a requirement was not achieved Each requirement shall have at least one VSL While it is preferable to have four VSLs for each requirement some requirements do not have multiple ldquodegreesrdquo of non-compliant performance and may have only one two or three VSLs Each requirement is assigned one or more VSLs in accordance with the latest approved set of VSL criteria7

The most current version of the approved NERC Reliability Standard template and its associated elements as or if applicable will be used at the time of the development of the NPCC Rregional Rreliability Sstandard to ensure all essential elements are contained therein to achieve consistency and uniformity and meet all statutory requirements

Table 1- Elements of a Regional Reliability Standard [update or delete]

Identification Number

A unique identification number assigned in accordance with an administrative classification system to facilitate tracking and reference (ie ldquoNPCC- BAL-002-0-Daterdquo which refers to NPCC Regional Standard referencing NERC BAL-002 Version 0 with NPCC Effective Date-final adoption by all Regional Authorities)

Title A brief descriptive phrase identifying the topic of the standard

Applicability Clear identification of the functional classes of entities responsible for complying with the standard noting any specific additions or exceptions

Formatted Highlight

Comment [kbc34] Will we maintain footnote from NERC document

Comment [kbc35] Is this how we envisage the process to work in NPCC

Formatted Highlight

Comment [kbc36] Will we maintain footnote

Comment [kbc37] Maintain footnote

11

The standard will be applicable to the Bulk Power System unless otherwise noted

Effective Date and Status

The effective date of the standard or prior to approval of the standard the proposed effective date If the effective date is tied to a regulatory approval the verbal formula indicating when the Regional standard is to become effective

Purpose The Results-Based purpose of the standard The purpose shall explicitly state what outcome end result will be achieved or is expected by from this Regional standard

Requirement(s) Explicitly stated Results-Based technical performance and preparedness requirements Each requirement identifies what entity is responsible and what action is to be performed or what outcome result is to be achieved Each statement in the requirements section shall be a statement for which compliance is mandatory

Risk Factor(s)

The potential reliability significance of each requirement designated as a High Medium or Lower Risk Factor in accordance with the criteria listed below

A High Risk Factor requirement (a) is one that if violated could directly cause or contribute to bulk power system instability separation or a cascading sequence of failures or could place the bulk power system at an unacceptable risk of instability separation or cascading failures or (b) is a requirement in a planning timeframe that if violated could under emergency abnormal or restorative conditions anticipated by the preparations directly cause or contribute to bulk power system instability separation or a cascading sequence of failures or could place the bulk power system at an unacceptable risk of instability separation or cascading failures or could hinder restoration to a normal condition

A Medium Risk Factor requirement (a) is a requirement that if violated could directly affect the electrical state or the capability of the bulk power system or the ability to effectively monitor and control the bulk power system but is unlikely to lead to bulk power system instability separation or cascading failures or (b) is a requirement in a planning timeframe that if violated could under emergency abnormal or restorative conditions anticipated by the preparations directly affect the electrical state or capability of the bulk power system or the ability to effectively monitor control or restore the bulk power system but is unlikely under emergency abnormal or restoration conditions anticipated by the preparations to lead to bulk power system instability separation or cascading failures nor to hinder restoration to a normal condition

A Lower Risk Factor requirement is administrative in nature and (a) is a requirement that if violated would not be expected to affect the electrical state or capability of the bulk power system

12

or the ability to effectively monitor and control the bulk power system or (b) is a requirement in a planning time frame that if violated would not under the emergency abnormal or restorative conditions anticipated by the preparations be expected to affect the electrical state or capability of the bulk power system or the ability to effectively monitor control or restore the bulk power system

Measure(s) Each requirement shall be addressed by one or more measures Measures are used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measure will identify to whom the measure applies and the expected level of performance or outcomes required demonstrating compliance Each measure shall be tangible practical and as objective as is practical It is important to realize that measures are proxies to assess required performance or outcomes Achieving the measure should be a necessary and sufficient indicator that the requirement was met Each measure shall clearly refer to the requirement(s) to which it applies

Table 2 Compliance Elements of a Regional Reliability Standard Compliance Monitoring Process

Defines for each measure

bull The specific data or information that is required to measure performance or outcomes

bull The entity that is responsible for providing the data or information for measuring performance or outcomes

bull The process that will be used to evaluate data or information for the purpose of assessing performance or outcomes

bull The entity that is responsible for evaluating data or information to assess performance or outcomes

bull The time period in which performance or outcomes is measured evaluated and then reset

bull Measurement data retention requirements and assignment of responsibility for data archiving

bull Violation severity levels Supporting Information Elements Interpretation Any interpretation of regional reliability standard that is

developed and approved in accordance with the ldquoInterpretation of Standardsrdquo section of Appendix A of this procedure to expound on the application of the standard for unusual or unique situations or to provide clarifications

Implementation Each regional reliability standard shall have an associated

13

Plan implementation plan describing the effective date of the standard or effective dates if there is a phased implementation The implementation plan may also describe the implementation of the standard in the compliance program and other considerations in the initial use of the standard such as necessary tools training etc The implementation plan must be posted for at least one public comment period and is approved as part of the ballot of the standard

Supporting References

This section references related documents that support reasons for or otherwise provide additional information related to the regional reliability standard Examples include but are not limited to

bull Glossary of terms

bull Developmental history of the standard and prior versions

bull Notes pertaining to implementation or compliance

bull Standard references

bull Standard supplements

bull Procedures

bull Practices

bull Training references

bull Technical references

bull White papers

bull Internet links to related information

Formatted Normal Indent Left 025Numbered + Level 1 + Numbering Style 1 23 hellip + Start at 2 + Alignment Left + Alignedat 05 + Tab after 075 + Indent at 075 Dont adjust space between Latin andAsian text Dont adjust space between Asiantext and numbers Tab stops 05 List tab +Not at 075

14

3 3 KEY PARTICIPANTS ROLES TERMS AND FUNCTIONS

bull NPCC Board of Directors (BOD Board) - The NPCC BOD shall consider for adoption regional reliability standards definitions variances and interpretations and associated implementation plans that have been processed according to the processes identified in this manual In addition the bBoard shall consider for approval VRFs and VSLs associated with each approved regional standard Once the BOD adopts a regional reliability standard definition variance or interpretation or implementation plan or once the BOD approves VRFs or VSLs the Bboard shall direct NPCC staff to submit the document(s) for approval by the NERC Board of Trustees

bull NPCC Members - The ballot body is comprised of all entities or individuals that

qualify for one of the stakeholder sectors within NPCC and as approved bystated in the NPCC BODBylaws All General and Full Members of NPCC can participate in the balloting of regional standards

bull Regional Standards Committee (RSC)mdashAn NPCC committee BOD -

appointed committee charged with management and oversight of the NPCC Regional Reliability Standards Procedure Process for development of regional standards VRFs VSLs definitions variances interpretations and implementation plans in accordance with this manual under a the sector based voting structure as described in the NPCC Bylaws

The RSC is an open and balanced stakeholder committee inclusive of all stakeholder interests that provide for or are materially impacted by the reliability of the bulk power system Its responsibilities are defined in detail in the NPCC RSC Scope

bull The NPCC RSC will consider requests for new or revised regional reliability standards and be available for advisement to the NPCC Board BOD on theregional standards and standards related issues in general

The RSC may not itself materially modify mandatory and enforceable sections of the a regional standard except without issuing a new notice to stakeholders regarding a vote of the modified standard Any RSC action will only be activated in the event of a minor corrections of to a the standard such as errata The RSC may make or revisions to the sections of the regional standard that are not mandatory and enforceable The RSC is responsible for managing the standards processes for development of standards VRFs VSLs definitions variances and interpretations in accordance with this manual The responsibilities of the RSC are defined in detail in the NPCC RSC Scope The RSC is responsible for ensuring that the regional standards VRFs VSLs definitions variances and interpretations and implementation plans developed by drafting teams are developed in accordance with the processes in this manual and meet NERCrsquos and FERCrsquos benchmarks for reliability standards including criteria for all governmental approvals

Formatted Font Bold Underline

Formatted Font Bold

Formatted Font 12 pt Font color Auto

Formatted Bullets and Numbering

Comment [kbc38] For consistency with whats stated on page 4



Formatted List Paragraph No bullets ornumbering Adjust space between Latin andAsian text Adjust space between Asian textand numbers

Comment [kbc39] The original text seems to confuse two ideas What do we really want to say

Comment [kbc40] Reference needed

Formatted Indent Left 075 No bullets ornumbering

Comment [kbc41] Not necessary since the RSC itself does not change the standard even after issuing this notice

Comment [kbc42] We need to describe guidelines or criteria for these modifications to be undertaken by the RSC and the process to be followed including some notification to members and request for comments Revisions to the compliance elements of a regional standard say without stakeholder notice and input could be controversial

Formatted Font 12 pt


Comment [kbc43] The process for developing VRFs and VSLs is not described





Comment [kbc44] Whats this Clarification needed


Comment [kbc45] Reference needed()

15

The RSC is an open and balanced stakeholder committee inclusive of all stakeholder interests that provide for or are materially impacted by the reliability of the bulk power system

The RSC disposition regarding the rRegional sStandard aAuthorization rRequest (RSAR) which will in all cases be within 60 calendar days of receipt of a completed standard requestRSAR shall includebe one of the following

bull Accept the standard request as a candidate for development of a new standard revision of an existing standard or deletion of an existing standard The RSC may at its discretion expand or narrow the scope of the standard request under consideration The RSC shall prioritize the development of standards in relation to other proposed standards as may be required based on the volume of requests and resources

bull Reject the standard request If the RSC rejects a standard request a written explanation for rejection will be delivered to the requester within 30 calendar days of the decision

bull Remand the standard request back to the requester for additional work The NPCC standards process managerstaff will make reasonable efforts to assist the requester in addressing the deficiencies identified by the RSC The requester may then resubmit the modified standard request using the process above The requester may choose to withdraw the standard request from further consideration prior to acceptance by the RSC

The NPCC Standard Process responsibilities of the RSC will include

bull Review of NPCC Draft Standards (for such factors as completeness sufficient detail rational result and compatibility with existing NERC and other Regional standards) and clarifying standard development issues not specified in this procedure Under no circumstance will the RSC unilaterally make anysubstantial changes to the substancemandatory and enforceable sections essence of a draft standard

bull Ensure that the drafting team has given Ddue consideration to the work of the drafting team as well as the comments of stakeholders and minority objections in approving a proposed regional reliability standard to go to ballot

bull Approve standards for pre-ballot posting under a sector based voting structure as described later in the NPCC Inc Bylaws or

bull Remand the standard back to the Task Force acting as the drafting team for further work or recommend a change in those participating in the drafting team (ie a new drafting team)

bull NPCC Standards Staff mdash- The standards staff led by the Assistant Vice-

President of Standards is responsible for administering NPCCrsquos Rregional rReliability sStandards pProcesses in accordance with this manual The standards staff provides support to the RSC in managing the standards processes and in supporting the work of all regional drafting teams The


Comment [kbc47] Here weve started getting into process details which are repeated in the process description later on (Steps 1 amp 2) Suggest removing this paragraph and the next 3 bullets and placing withing the section describing steps 1 amp 2

Comment [kbc48] Shouldnt this be an NPCC staff function Does RSC have the resources to do this

Comment [kbc49] Repetition See above Delete one occurrence

Comment [kbc50] If the TF is involved in drafting the regional standard who would this work










16

standards staff works to ensure the integrity of the standards processes and consistencyt of quality and completeness of the reliabilityregional standards through drafting team support and conducting quality reviews The standards staff facilitates all steps in the development of regional standards definitions variances interpretations and associated implementation plans The standards staff works with drafting teams in developing VRFs and VSLs for each regional standard The standards staff is responsible for presenting regional standards definitions variances and interpretations and associated implementation plans to the NPCC BOD for adoption When presenting standards-related documents to the NPCC BOD for adoption or approval the standards staff shall report the results of the associated stakeholder ballot including identification of unresolved stakeholder objections and an assessment of the documentsrsquos practicality and enforceability as well as any polling information obtained during standard development

bull Regional Standards Process Manager (RSPM) - The Regional Reliability

Standards Procedure shall be administered by a NPCC staff Regional Standards Process Manager The RSPM is responsible for ensuring that the development and revision of standards is in accordance with this manual The RSPM works to ensure the integrity of the process format consistency of quality and completeness of the reliability standards The RSPM facilitates all steps in the process

bull Reliability Coordinating Committee (RCC) mdash The RCC will support the

standards development process through the assignment of NPCC Task Forces They will may also provide perform a technical advisory role in the Regional Reliability Standards development procedureprocess through comments and recommendations

bull Requester mdash A Requester is any individual or an entity (organization company government authority including the RSC etc) that submits a completed request for development revision or withdrawal of a regional standard Any person or an entity that is directly and materially affected by an existing standard or the need for a new standard may submit a request for a new standard or revision to a standard The Requester is assisted by the RSAR drafting team (if one is appointed by the RSC) or NPCC standards staff to respond to comments and to decide if and whencomplete the drafting of the RSAR is prior to it being forwarded to the RSC with a request to draft a regional standard The Requester is responsible for the RSAR assisted by the RSAR drafting team and or Regional Standards Process ManagerNPCC standards staff until such time the RSC authorizes development of the standard The Requester has the option at any time to allow the RSAR drafting team to assume full responsibility for the RSAR The Requester may choose to participate in subsequent standard drafting efforts related to the RSAR














Comment [kbc51] At what point do they do this During Open Process postings or are there other occasions

Comment [kbc52] Where did this come from It was not highlighted earlier as one of the RSCs responsibilities not in flow chart currently

17

bull Task Forces and Working Groups mdash The committees task forces and working groups within NPCC serve an active role in the standards process as follows

bull Identify the need for new or modified regional standards bull Initiate NPCC Standards actions by developing Regional Standard

Authorization Requests (RSARs) bull Develop comments (views and objections) to standards actions bull Participate in NPCC Standard drafting activities bull Provide technical oversight in response to changing industry conditions

and ERO Requirements bull Determine the need for and Cconduct Field field Teststests as required bull bull Determine the need for and perform necessary data collection and

surveys to develop the standard as required bull NPCC Compliance Committee (CC) - [Stanley to provide write up]

bull Compliance Monitoring and Enforcement Program - The NERC

compliance monitoring and enforcement program manages and enforces compliance with approved regional and NERC reliability standards The compliance program area shall provide feedback to drafting teams during the standards development process to ensure the compliance enforcement program can be practically implemented for the standards under development The compliance enforcement program may conduct field tests or data collection related to compliance elements of proposed standards and may provide assistance with field tests or data collection when requested The compliance enforcement program shares its observations regarding the need for new or modified requirements with the standards staff for use in identifying the need for new standards projects

4 4 PROCEDURE DESCRIPTION

STEPS 1 AND 2 REQUEST TO DEVELOP A NEW REGIONAL STANDARD A Requester may Rrequests to the development of

a new Rregional Reliability Sstandard

or revision of an existing standard by submitting a Regional Standard Authorization Request (RSAR) form shall be submitted to the NPCC Manager of Reliability Standards who will promptly acknowledge receipt RSPM by completing a Regional Standard Authorization Request (RSAR) which may be found on the NPCC website(see Appendix A) The RSAR is a description of the new or revised regional standard in sufficient detail to clearly define the its scope purpose and importance of the Regional Standard impacted parties or and other relevant information A ldquoneedsrdquo statement will provide the justification for the development of the standard including an assessment of the reliability and market interface impacts of implementing or not implementing the standard The RSPMManager of Reliability Standards shall maintain retain the RSAR form and make it available electronically on the NPCC website Any person or entity (ldquoRequesterrdquo) directly or materially affected by an existing standard or the need for a new or revised standard may initiate a RSAR

Comment [kbc53] Are there guidelines on the setup approval approval etc of drafting teams


Formatted Indent Left 1 Hanging 013 No bullets or numbering

Formatted Font (Default) SymbolMT




Formatted Font Bold

Formatted Indent Left 05 Bulleted +Level 1 + Aligned at 1 + Tab after 125 +Indent at 125 Tab stops 075 List tab +Not at 125


Formatted Font Bold


Formatted Font Bold





Comment [kbc54] Vague Should this be NPCC Compliance staff


Comment [kbc55] When how How long - eg 5 business days Before posting May need an extra step





Formatted

Formatted Font Bold


Comment [kbc56] The left margin indent in this section needs to be made consistent with the rest of the document Also check for consistency in tense The procedure is for the most part written in future tense will Is this appropriate or should it be written in the present tense



Comment [kbc57] Repetition

18

The Requester will submit the RSAR to the RSPMManager of Reliability Standards electronically and the RSPMManager of Reliability Standards will acknowledge receipt of the RSAR immediately through electronic receipt The RSAR as a minimum needs shall to contain the following information in order to be qualified for consideration The NPCC RSPMManager of Reliability Standards will assist the Requester to ensure all required the following information is submitted (on the RSAR) such as in a form appearing in Appendix A

1 Proposed Title and Date of New RSAR 2 Requesterrsquos Name and Contact Information 3 Purpose of the Regional Standard 4 Description of Industry Need 5 Provide a Brief Description of the Standard 6 Identification of the Entities in the Functional Model as being responsible to

adhere to the standard 7 Necessary information to assist the drafting the team to the extent feasible to

allow them to draft the standard 8 Any existing known cross references to existing NPCC or NERC documents 89Technical background for the RSAR to properly address the need for the standard

The RSPMManager of Reliability Standards shall forward all properly completed RSARs to the RSC The RSC shall meet at established intervals to review all pending RSARs The frequency of this review process will depend on workload but in no case shall a properly completed RSAR wait for RSC action more than 60 calendar days from the date of receipt The RSC may take one of the following actions

bull Remand the RSAR back to the RSPMManager of Reliability Standards for additional work In this case the RSPMManager of Reliability Standards may request additional information or clarification for the RSAR from the Requester

bull Accept the RSAR as a candidate for a new or revised standard In this case the RSC will forward the RSAR to the RCC to assign a NPCC Task Force to provide technical support and analysis of comments for that RSAR and assist the Requester and the RSPMManager of Reliability Standards in drafting the RSARthe remaining steps of the process The RSPMManager of Reliability Standards shall within 60 calendar days of acceptance post notification of intent to develop a standard on both the NPCC website and notify the ERO to post the notification on its websites within 30 calendar days of acceptance

bull Reject the RSAR In this case the RSC will provide its determination to the Manager of Reliability Standards who will then provide a written explanation for rejection to the Requester within 30 60 calendar days of the rejection decision

STEPS 3 4 AND 5 RSC ACCEPTS RSAR AND RCC ASSIGNS TF TO DRAFT NEW OR REVISED STANDARD A RSAR that is accepted by the RSC will shall be submitted to the RCC who shall assign the development of the regional standard to a Task Force Wwithin 60 calendar days the RCC shall assign the development of the standard to a Task Force Drafting Team The RSPMManager of Reliability Standards shall oversee solicitation and recommendation of a list of additional candidates for appointment to the Drafting Tteam and shall submit the

Comment [kbc58] Not to the VP first

Comment [kbc59] No need to specify how

Comment [kbc60] of the completed RSAR

Comment [kbc61] The RSAR has been drafted already Is theis correct or does the TF assist with further refining of the RSAR This does not seem consistent with what follows in steps 3 4 and 5

Formatted Highlight

Comment [kbc62] By whom - MRS

19

list to the RSC This list shall include the Requester The RSC may select other individuals to serve in with the Task Force to drafting the Standard This The Drafting tTeam shall consist of a small group of people who collectively have the necessary technical expertise and work process skills to effectively and efficiently produce a quality standard andand the Drafting Team shall remain in place until such time as the NERC BOT adopts the regional standard Inquiries arising after a standardrsquos development shall be directed by the RSC to the tTask fForce to which the drafting of the standard was assigned The RSPMManager of Reliability Standards shall serve coordinate or assign NPCC staff personnel to assist in the drafting of the standard including compliance measures process and elements The drafting of measures and compliance administration aspects of the standard will be coordinated with the NPCC Compliance Program Staffarea When a drafting team begins its work either in refining an RSAR or in developing or revising a proposed standard the drafting team shall develop a project schedule and report its progress against that schedule to the RSC as requested through the Manager of Reliability Standards to the RSC against that schedule as requested by the RSC Once the Drafting Team has produceds a draft of the regional reliability standard VRFs VSLs variances and its associated implementation plan NPCC standards staff shall coordinates Quality Review of the draft standard consisting of technical writing legal and compliance reviews prior to submission to RSC

STEP 6 SOLICIT PUBLIC COMMENTS ON DRAFT REGIONAL STANDARD Once a draft standard has been verified by the RSC to be within the scope and purpose of the RSAR and the results of the Quality Review are deemed to be satisfactory the RSPMManager of Reliability Standards will post the draft standard for the purpose of soliciting public comments The posting of the draft standard will be linked to the RSAR for reference by its title In addition to the standard an implementation plan shall be posted to provide additional details to the public and aid in their commenting and decision process This implementation plan will be drafted and posted with draft standards upon the availability of sufficient information data or targeted survey results to determine a realistic schedule for implementation Comments on the draft standard will be accepted for a 45 calendar day period from the public notice of posting Comments will be accepted on-line using the NPCC Open Process web-based application The Manager of Reliability Standards will notify NERC to concurrently post fFinalthe draft standard and all associated documents will be concurrently posted on the ERO website for comments

STEPS 7 8 AND 9 OPEN PROCESS POSTING AND ANALYSIS OF THE COMMENTS The RSPMManager of Reliability Standards will assemble the comments on the new draft standard and distribute those comments to the Task Force acting as the standard dDrafting tTeam The Task ForceDrafting Team shall give prompt consideration to the written views and comments of all participants An effort to address all expressed submitted comments shall be madeaddressed and each commenter shall be advised of the disposition of their comments and the reasons therefore in addition toThe Manager of

Comment [kbc63] What is this intended to mean Standard development process What elements





Comment [kbc64] Who does the quality review Any criteria for this Where would the guidelines be found

Comment [kbc65] Not necessary since the Quality Review must be completed successfully before the draft standard gets to RSC

Comment [kbc66] We need more than just an effort

20

Reliability Standards shall publicly posting all of the Drafting Teamrsquos responses to stakeholder comments on the NPCC website The Task Force acting as the Standard Drafting Team shall take one of the following actions

bull Submit the draft standard for RCC endorsement as it stands along with the comments received and responses to the comments Based on the comments received the Drafting Team Task Force acting as the standard drafting team may include revisions that are not substantive A substantive change is one that directly and materially affects the application of the standard including for example changing ldquoshallrdquo to ldquoshouldrdquo changing ldquoshouldrdquo to ldquoshallrdquo adding deleting or revising requirements or adding deleting or revising measures for which compliance is mandatory

bull Make substantive revisions to the draft standard and reposts it for further open review and comment

bull Drafting Team Task Force recommends Field Test if necessary to RSC

Requester also may withdraw the request for the development of the regional standard at any time during the Regional Reliability Standard Processwithdraw the request for a standard

Upon receipt the RCC submits the proposed regional reliability standardRRS to the RSC along with its recommendation based on comments Drafting Team Task Force statements and any field test results

STEPS 10 AND 11 RSC APPROVES OF THE NEW OR REVISED STANDARD FOR POSTING If the RSC acting with consideration of any recommendations by the RCC and utilizing the composite sector voting structure as outlined in the NPCC Bylaws votes to post the draft regional standard for approval the draft standard all comments received and the responses to those comments shall be posted publicly electronically for the NPCC Members by the RSPMManager of Reliability Standards and made public throughon the NPCC Website website (wwwnpccorg) for a 30 calendar day ldquopre-ballot reviewrdquo and request for ballotingto be followed by an NPCC Member approval ballot If the RSC decides more work is needed the draft standard will be remanded back to the Drafting Teamdrafting Task Force All actions of the RCC Drafting Teams Task Forces acting as drafting teams and the Regional Standards Committee will be recorded in regular minutes of the group(s) and posted on the NPCC website Once the notice for a ballot has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued STEPS 12 13 AND 14 BALLOT OF STANDARD Upon notification of a ballot the Members of NPCCrsquos registered ballot body will cast their vote consistent with the NPCC Bylaws This ballot shall commence no sooner than 15 calendar days and no later than 30 calendar days following the notification of ballot All members of the NPCC are eligible to participate in the voting on proposed standard revisions or deletions of regional standards The ballot period will typically begin immediately following the 30 calendar day pre-ballot posting and will last at least 10 business days

Comment [kbc67] Not consistent with flowchart Box 9 in the flowchart needs to be corrected


Comment [kbc68] This statement just hangs here Perhaps it is better located in the section that describes Steps 1 and 2


Comment [kbc69] Change in tense

Comment [kbc70] Confusing Alternative text provided Is this okay

Comment [kbc71] This should either be the RCC or the Task Force to whom responsibility for drafting the regional standard was assigned

Formatted Keep with next

Formatted Indent First line 0

21

The NPCC registered ballot body comprises all entities or individuals that qualify for one of the eight NPCC stakeholder sectors and are registered with NPCC as potential ballot participants in the voting on standards Each member of the NPCC registered ballot body is eligible to vote on standards

In order for a NPCC Regional Standard to be approved

bull A quorum must be established by at least 50 of the NPCC Members of at least 60 of the Voting Sectors on the roster of Members maintained by NPCC

bull A two-thirds majority of the total weighted sector votes cast must be affirmative The number of votes cast is the sum of affirmative and negative votes excluding abstentions and non-responses Weighted sector vote will be calculated as follows o Affirmative votes cast in each sector will be divided by the sum of

affirmative and negative votes cast in that same sector to determine the fractional affirmative vote for each sector Abstentions and non-responses will not be counted for the purposes of determining the fractional affirmative vote for a sector

o The sum of the fractional affirmative votes from all sectors divided by the number of sectors voting will be used to determine if a two-thirds majority has been achieved (A sector will be considered as ldquovotingrdquo if any member of the sector in the ballot pool casts either an affirmative or a negative vote)

o A standard will be approved if the sum of fractional affirmative votes from all sectors divided by the number of voting sectors is at least 23

Ballots will be cast electronically and alternatives are as follows

bull Affirmative bull Affirmative with Comments bull Negative bull Negative with Comments bull Abstain

The RSPMManager of Reliability Standards shall post the final outcome of the ballot process If the regional standard is rejected it may be withdrawn by either the RCCRSC or the original Requester or the standard may be remanded by the RSC back to the Drafting TeamTask Force acting as the drafting team to address the issuesballotersrsquo comments In the event the proposed regional standard is withdrawn Aall comments submitted during the process will be posted and archived for consideration when redrafting the standard upon review The standard oOnce the Member ballot approvesd by ballotthe regional standard the Manager of Reliability Standards shall and a recommend final regional approval ation will be forwarded to the NPCC Board BOD for final Regional approval The Board NPCC BOD may not make substantive modifications to the standard If the Board NPCC BOD does not approve the standard for transmittal to NERC it will be remanded back to the RSC to address RCC comments

Comment [kbc72] Not consistent with flow chart This should be RSC

Comment [kbc73] Task Force to whom responsibility for drafting the standard was assigned

Comment [kbc74] From the context it seems the following actions will be take under these conditions

Comment [kbc75] The process does not address comments submitted with a ballot if the standard passes the vote As a result dissenting balloters concerns will be ignored (filed in the issues database for future reference) That is there is no equivalent of a recirculation ballot

22

If the RCC approves the regional standard is approved the Manager of Reliability Standards standard will be submitted the standard to the NERCERO Board of Trustees for approval STEPS 15 16 AND 17 IMPLEMENTATION OF THE NPCC REGIONAL STANDARD Upon approval within by the NPCC BOD the Manager of Reliability Standards shall submit the regional standard will be submitted to the NERCERO for approval(s) and filing with FERC and applicable Canadian Governmental andor Regulatory Authorities for adoption Once a reliability regional standard is adopted by the NERC BOT and submitted to and approved by either FERC andor applicable Canadian Governmental andor Regulatory Authorities andit shall made becomes effective in the applicable jurisdiction in accordance with its associated implementation plan aAll users owners planners and operators of the Bulk Power System in the NPCC geographic area of the Northeast North America are will be required to comply with the standard at this time The NERCERO Board of Trustees has established its Compliance Monitoring and Enforcement Programa separate compliance program also administered in the Northeast by NPCC to measure compliance with the reliability standards and administer sanctions as appropriate After adoption of a NPCC Rregional Sstandard the standard will be included in the forwarded to the compliance program for NERCERO compliance Compliance mMonitoring and eEnforcement Program STEP 18 WITHDRAWAL ORF REMAND OF A REGIONAL STANDARD Upon voter rejection or upon the request for the withdrawal of a proposed standard made to the the RSC CC or the requester may the RSC may elect to withdraw the standard completely or remand it back to the Task ForceDrafting Team acting as the standard drafting team for further work The Assistant Vice President-Standards will inform NERC and the industry of the actions taken

Comment [kbc76] Include VRFs VSLs Implementation Plan or do we interpret standard to include all these items

Comment [kbc77] At what time when approved or as defined in the implementation plan

Formatted Highlight

Comment [kbc78] Correct

23

RSRSubmissionto RSPM

1

RSC Review

2

Valid 3

RCC Assigns TF and also RSPM

posting Of intent to draft a

standard4

Task Force Drafts Standard

5

Open Process Postings

6

Comments7

TF Addresses Comments

Redrafts StdFTwithdrawn

8

TF Submits to RSC for Review

with all backgound and Recs

9

RSC Approves10

Post for Preballot Review

11

Standard Balloted

12

Passed13

Standard Submitted to ERO

15

Filed wFERC and Canadian Authorities

Adopted and Standard

Implemented17

RSC or Requester Withdraws

14

Yes

No

Yes

No

Yes

No

Yes

NoNo

5 FlowchartRegional Standards

Development Procedure(Open Process)

ERO Process of Approval and BOT

Approval

16

Complete Withdrawal or sent back to the

Drafting Team

18

24

6 ERO AND REGULATORY PROCESS AND APPROVALS

bull NERCERO Comment Period mdash Concurrent with regional posting of final drafts the final drafts will be forwarded to NERC for posting on the NERC website to ensure full industry awareness of the standard and expedite and coordinate all commenting NERCERO shall publicly notice and request comment on the NPCC Rregional Rreliability Sstandard and associated implementation plan allowing a minimum of 45 calendar days for comment on NERCrsquos website and actively notify all adjoining Regions Concurrent with this regional posting of final drafts the final drafts will be forwarded to NERC for posting on the NERC website to ensure full industry awareness of the standard and expedite and coordinate all commenting All comments will be responded to electronically by the Drafting Team through a posted response on the NPCC website or a link on the NERC website NPCC shall have an opportunity to resolve any objections identified in the comments and may choose to withdraw the requestposting for comment revise the NPCC Rregional Reliability Sstandard and request another posting for comment or submit the NPCC Rregional Rreliability Sstandard along with a response to any objections received for approval by NERC

bull NERCERO Approval of NPCC Regional Reliability Standards mdash

Proposed regional reliability standards shall be subject to approval by the NERCERO who shall have a process to evaluate and recommend whether a proposed non-Interconnection-wide NPCC Rregional Rreliability Sstandard has been developed in accordance with all applicable procedural requirements and whether NPCC has considered and addressed stakeholder objections NPCC BoardBOD having been notified of the results of the regional ballot concerning a NPCC Rregional Rreliability Sstandard shall vote to submit the Sstandard to the NERCERO Board BOT for approval as a NERC Rreliability Standardstandard The NERCERO Board BOT shall consider NPCCrsquos request the scope and implications of the Sstandard the recommendation for action on the Sstandard any unresolved stakeholder comments and NPCCrsquos consideration of comments and unresolved issues if any in determining whether to approve the NPCC Rregional Rreliability Sstandard as a NERC Rreliability Sstandard

bull Regulatory Authority Approval mdash An NPCC Rregional Rreliability

Sstandard that has been approved by the NERCERO board BOT shall be filed with FERC and applicable Canadian Governmental andor Regulatory Authorities for approval and shall become effective and enforceable within the US per Section 215 of the Federal Power Act only when adopted by FERC and within individual Canada provinces only when adopted by applicable Canadian Governmental andor Regulatory Authorities in accordance with any associated implementation plan The regional reliability standard once adopted will be made part of the body of NERC reliability standards and shall be mandatory and enforceable on all applicable bulk power system owners operators and users within the NPCC Region in accordance with any associated implementation plan regardless of membership status

Comment [kbc79] Consider including a list with acronyms explained for the convenience of the reader

Formatted Underline Small caps

Comment [kbc80] Should this be 16 and 17


Formatted Small caps

Comment [kbc81] Posting for pre-ballot review or comment

Comment [kbc82] anything else

Comment [kbc83] Moved above for better sequencing

Comment [kbc84] The possible outcomes have not been specified ie Accept Remand Reject What happens if NERCERO does not approve the regional standard

25

7

Appeals

bull Persons who have directly and materially affected interests and who have been or will be adversely affected by any substantive or procedural action or inaction related to the development approval revision reaffirmation or withdrawal of a regional reliability standard shall have the right to appeal This appeals process applies only to the standards process as defined in this procedure The burden of proof to show adverse effect shall be on the appellant Appeals shall be made within 30 calendar days of the date of the action purported to cause the adverse effect except appeals for inaction which may be made at any time In all cases the request for appeal must be made prior to the next step in the process The appeal must be in writing signed by an officer of the appellant

The final decisions of any appeal shall be documented in writing and made public

The appeals process provides two levels with the goal of expeditiously resolving the issue to the satisfaction of the participants

bull Level 1 Appeal

Level 1 is the required first step in the appeals process The appellant submits a complaint in writing to the RSPMManager of Reliability Standards that describes the substantive or procedural action or inaction associated with a reliability standard or the standards process The appellant describes in the complaint the actual or potential adverse impact to the appellant Assisted by any necessary staff and committee resources the RSPMManager of Reliability Standards shall prepare a written response addressed to the appellant as soon as practical but not more than 45 calendar days after receipt of the complaint If the appellant accepts the response as a satisfactory resolution of the issue both the complaint and response will be made a part of the public record associated with the standard and posted with the standard

bull Level 2 Appeal

If after the Level 1 Appeal the appellant remains unsatisfied with the resolution as indicated by the appellant in writing to the NPCC regional standards process manager the RSPMAssistant Vice-President of Standards the NPCC Assistant Vice-President of Standards shall request the BOD to convene a Level 2 Appeals Panel This panel shall consist of five members total appointed by the NPCCrsquos bBoard

In all cases Level 2 Appeals Panel members shall have no direct affiliation with the participants in the appeal

The RSPMManager of Reliability Standards shall post the complaint and other relevant materials and provide at least 30 calendar days notice of the

Comment [kbc85] Ensure this appeals process is consistent with MOUs with Canadian entities The CCEP document currently posted for ballot has been amended to achieve consistency with the Ontario appeals process contained in the MOU

Comment [kbc86] Form of the appeal Could also add language similar to the objection lower down ie contain a concise statement of

Comment [kbc87] How much time does the appellant have to write

Comment [kbc88] Is sector representation needed here if so how will this work with only 6 sectors

26

meeting of the Level 2 Appeals Panel In addition to the appellant any person that is directly and materially affected by the substantive or procedural action or inaction referenced in the complaint shall be heard by the panel The panel shall not consider any expansion of the scope of the appeal that was not presented in the Level 1 Appeal The panel may in its decision find for the appellant and remand the issue to the RSC with a statement of the issues and facts in regard to which fair and equitable action was not taken The panel may find against the appellant with a specific statement of the facts that demonstrate fair and equitable treatment of the appellant and the appellantrsquos objections The panel may not however revise approve disapprove or adopt a reliability standard The actions of the Level 2 Appeals Panel shall be publicly posted

In addition to the foregoing a procedural objection that has not been resolved may be submitted to the NPCC Board for consideration at the time the board decides whether to adopt a particular regional reliability standard The objection must be in writing signed by an officer of the objecting entity and contain a concise statement of the relief requested and a clear demonstration of the facts that justify that relief The objection must be filed no later than 30 calendar days after the announcement of the vote on the standard in question Process for Developing an Interpretation Any entity that is directly and materially affected by the reliability of the North American bulk power systems may request an interpretation of any requirement in any regional standard that has been adopted by the NERC BOT A valid interpretation request is one that requests additional clarity about one or more requirements in approved NPCC regional reliability standards but does not request approval as to how to comply with one or more requirements A valid interpretation response provides additional clarity about one or more requirements but does not expand on any requirement and does not explain how to comply with any requirement Any entity that is directly and materially affected by the reliability of the North American bulk power systems may request an interpretation of any requirement in any regional standard that has been adopted by the NERC BOT The entity requesting the interpretation shall submit a Request for Interpretation form to the NPCC Manager of Reliability Standards explaining the clarification required the specific circumstances surrounding the request and the impact of not having the interpretation provided The NPCC Manager of Reliability Standards shall work with the requester to ensure that the request for interpretation form is complete and necessary The NPCC Manager of Reliability Standards utilizing the NPCC Task Force structure shall assemble an interpretation drafting team with the relevant expertise to address the clarification As soon as practical the team shall




Comment [kbc89] May also need processes to develop a definition and retire a standard along with flowcharts


Comment [kbc90] Is this to be restricted to within the NPCC area or will any entity anywhere in North America be able to make a request



Comment [kbc92] Who makes this determination - NPCC staff


Comment [kbc93] What about other parts of the standard



Comment [kbc94] Who makes this determination


Comment [kbc95] Only requirements





Formatted Font 12 pt Not Italic Font colorAuto



Comment [kbc96] Why do we need this



Comment [kbc97] For development of a new standard the RCC assigned the standard development to a Task Force Shouldnt we adopt a similar approach here


27

develop a ldquofinal draftrdquo interpretation providing the requested clarity RCC need to get involved The NPCC Manager of Reliability Standards shall coordinate a quality review of the interpretation to assess whether the interpretation is clear and provides the requested clarity without expanding on any requirement The detailed results of this review shall be provided to the regional standard drafting team and the RSC with a recommendation on whether the documents are ready for formal posting and balloting and iIf the RSC agrees that the proposed interpretation passes this review the RSC shall authorize posting the proposed interpretation to the NPCC website The first formal comment period shall be 30- days long If the drafting team makes substantive revisions to the interpretation following the initial formal comment period then the interpretation shall undergo another quality review before it is posted for its second formal comment period The second formal comment period shall have a 45-day duration and shall start after the drafting team has posted its consideration of stakeholder comments and any conforming changes to the associated regional standard Notification of a ballot shall take place during the first 30 days of the 45-day formal comment period and the ballot of the interpretation shall take place during the last 10 days of that formal comment period The interpretation drafting team shall consider and respond to all comments submitted during the formal comment period at the same time and in the same manner as specified for addressing comments submitted with ballots All comments received and all responses shall be publicly posted to the NPCC website Stakeholders who submit comments objecting to some aspect of the interpretation shall determine if the response provided by the drafting team satisfies the objection All objectors shall be informed of the appeals process contained within this manual A ballot will be conducted utilizing quorum and approval requirements as outlined in the NPCC Bylaws If stakeholder comments indicate that there is not consensus for the interpretation and the interpretation drafting team cannot revise the interpretation without violating the basic expectations outlined above the interpretation drafting team shall notify the RSC of its conclusion and shall submit a RSAR with the proposed modification to the standard The entity that requested the interpretation shall be notified and the disposition of the interpretation shall be posted to the NPCC website If during its deliberations the interpretation drafting team identifies a reliability gap in the regional standard that is highlighted by the interpretation request the interpretation drafting team shall notify the RSC of its conclusion and shall submit a RSAR with the proposed modification to the standard at the same time it provides its proposed interpretation

Comment [kbc98] Not at this stage















Comment [kbc99] Whats the significance of this





Formatted Indent Left 075 Space After 0 pt


Formatted Font 12 pt Font color AutoHighlight

Formatted Highlight






Formatted Font 12 pt Highlight



28

If approved by its ballot the interpretation shall be appended to the standard and forwarded to the NPCC BOD for adoption If an interpretation drafting team proposes a modification to a regional standard as part of its work in developing an interpretation the BOD shall be notified of this proposal at the time the interpretation is submitted for adoption Following adoption by the BOD NPCC standards staff shall submit the interpretation for approval by the NERC BOT Once approved by the NERC BOT NPCC standards staff shall file the interpretation with FERC and applicable Canadian Governmental andor Regulatory Authorities for approval The standard shall become effective and enforceable within the US only when adopted by FERC and within individual Canada provinces only when adopted by applicable Canadian Governmental andor Regulatory Authorities in accordance with any associated implementation plan and the interpretation shall not become effective until approved by applicable governmental authorities The interpretation shall stand until such time as the interpretationit can be incorporated into a future revision of the regional standard or the interpretation is retired due to a future modification of the applicable requirement

Some general comments bull Complete quality check required bull ldquoProcessrdquo and ldquoprocedurerdquo are used interchangeably throughout Check for and achieve consistency bull Check for and ensure consistency in usage ldquoAn NPCCrdquo or ldquoA NPCChelliprdquo Eg see highlights on pg 4 bull Process Qn Maintenance of standards Who performs the review to determine the need to revise an existing

reliability standard ndash NPCC Staff RSC Task Force NPCC staff may trigger the review but who will do it bull Consistency check When ldquoregional reliability standardsrdquo is not used as part of a title (eg Regional Reliability

Standards Processrdquo it should be preceded by ldquoNPCCrdquo Also we must decide whether it will be capitalized or not We suggest at the first occurrence introduce a short description ie ldquohellipNPCC regional reliability standards (regional standards)helliprdquo and then use ldquoregional standardsrdquo throughout the remainder of the document

bull Consistency check Drafting Team vs Standard Drafting Team We prefer the former for consistency with NERC bull


Comment [kbc100] By whom






Formatted Font (Default) Calibri 10 pt

Formatted Indent Left 0 Hanging 013Bulleted + Level 1 + Aligned at 025 +Indent at 05

Formatted Font (Default) Calibri 10 ptEnglish (Canada)

29

30

Appendix A

Information in a Regional Standard Authorization Request (RSAR)

The tables below identify information to be submitted in a Regional Standard Authorization Request to the NPCC Regional Standards Process Manager

NPCCstandardnpccorg The NPCC Regional Standards Process Manager shall be responsible for implementing and maintaining this form as needed to support the information requirements of the standards process

Regional Standard Authorization Request Form

Title of Proposed Standard

Request Date

RSAR Requester Information

Name RSAR Type (Check box for one of these selections)

Company New Standard

Telephone Revision to Existing Standard

Fax Withdrawal of Existing Standard

31

Email Urgent Action

Purpose (Describe the purpose of the proposed standard ndash what the standard will achieve in support of reliability)

Industry Need (Provide a detailed statement justifying the need for the proposed standard along with any supporting documentation)

Brief Description (Describe the proposed standard in sufficient detail to clearly define the scope in a manner that can be easily understood by others)

Reliability Functions

The Standard will Apply to the Following Functions (Check all applicable boxes)

Reliability Coordinator

The entity that is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System has the Wide Area view of the Bulk Electric System and has the operating tools processes and procedures including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations The Reliability Coordinator has the purview that is

32

broad enough to enable the calculation of Interconnection Reliability Operating Limits which may be based on the operating parameters of transmission systems beyond any Transmission Operatorrsquos vision

Balancing Authority

The responsible entity that integrates resource plans ahead of time maintains load-interchange-generation balance within a Balancing Authority Area and supports Interconnection frequency in real time

Interchange Authority

Authorizes valid and balanced Interchange Schedules

Planning Authority

The responsible entity that coordinates and integrates transmission facility and service plans resource plans and protection systems

Transmission Service Provider

The entity that administers the transmission tariff and provides Transmission Service to Transmission Customers under applicable transmission service agreements

Transmission Owner

The entity that owns and maintains transmission facilities

Transmission Operator

The entity responsible for the reliability of its ldquolocalrdquo transmission system and that operates or directs the operations of the transmission facilities

Transmission

The entity that develops a long-term (generally one year and beyond) plan for the reliability

33

Planner (adequacy) of the interconnected bulk electric transmission systems within its portion of the Planning Authority Area

Resource Planner

The entity that develops a long-term (generally one year and beyond) plan for the resource adequacy of specific loads (customer demand and energy requirements) within a Planning Authority Area

Generator Operator

The entity that operates generating unit(s) and performs the functions of supplying energy and Interconnected Operations Services

Generator Owner

Entity that owns and maintains generating units

Purchasing-Selling Entity

The entity that purchases or sells and takes title to energy capacity and Interconnected Operations Services Purchasing-Selling Entities may be affiliated or unaffiliated merchants and may or may not own generating facilities

Distribution Provider

Provides and operates the ldquowiresrdquo between the transmission system and the customer

Load-Serving Entity

Secures energy and transmission service (and related Interconnected Operations Services) to serve the electrical demand and energy requirements of its end-use customers

Reliability and Market Interface Principles

34

Applicable Reliability Principles (Check all boxes that apply)

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

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

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

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

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

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

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

Does the proposed Standard comply with all of the following Market Interface Principles (Select lsquoyesrsquo or lsquonorsquo from the drop-down box)

35

Recognizing that reliability is an Common Attribute of a robust North American economy

A reliability standard shall not give any market participant an unfair competitive advantageYes

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

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

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

Detailed Description (Provide enough detail so that an independent entity familiar with the industry could draft a standard based on this description)

Related Standards

36

Standard No

Explanation

-t

Related SARs or RSARs

SAR ID Explanation

37

of 5

Formatted Font color Auto

Approved by NPCC Board of Directors 9-17-08XX-XX-XXXX

Draft Scope of Work for the

Regional Standards Committee (RSC)

The NPCC Regional Standards Committee (RSC) a committee of the NPCC Board of Directors (BOD) is charged with

(a) managing the NPCC Regional Standards Ddevelopment Procedureprocess and

(b) managing the NPCC Directory and Criteria development process (bc) providing consolidated NPCC Regional review and comment to the

existing and proposed NERC Standards and participatinge in the NERC Reliability Standards Development Pprocessdure

(d) reviewing the FERC Orders Rulings and Notice of Proposed Rulemakings (NOPRs) related to reliability standards and providinge a forum for developing consensus viewpoints and submitting comments to FERC as necessary

(e) reviewing NERC Compliance Application Notices (CANs) working in coordination with the NPCC Compliance Committee (CC) and submitting comments to NERC as necessary

(e) responding to emerging standards related issues and providing support to members on an ad hoc basis for information related to NERC Alerts and Standards

(f) providing oversight and process for interpretation of Regional Standards and Criteria

(g) initiate changes to NERC and Regional Standards and Criteria after event analysis and lessons learned to reflect improvements to reliability

The RSC is an open and balanced stakeholder committee inclusive of all stakeholder interests that provide for or are materially impacted by the reliability of the bulk power system The RSC meetings will be open to all stakeholders who want to attend and will be publicly posted on the NPCC website

Decisions of the NPCC RSC RSC will be adopted under a sector based voting structure as described in the NPCC Bylaws

The RSC will coordinate its work with the Assistant Vice PresidentmdashStandards who will


Page 2 of 5

be the administrator for the NPCC Regional Standards Process and the coordinator of the review and submission of comments

The RSC will be chaired by an NPCC member of staff who will be assisted by the NPCC Regional Standards Process Manager (also a member of NPCC staff) along with co-vice chairs elected by the RSC from the existing members of the committee at the time the vote is taken Co-vice chairs will serve a term of two years with an additional extension of time available through a motion and subsequent vote by the committee in accordance with the NPCC Bylaws

Members of the RSC will be elected by the NPCC Board The eight[] NPCC Sectors as outlined in the NPCC Bylaws each will be represented on the RSC

Subcommittees and ad hoc Working Groups will be formed upon request of the RSC by NPCC standards program area staff and all associated scopes or charters developed will be approved by the RSC in accordance with the most recent approved and adopted NPCC Bylaws

The NPCC RSC will work in coordination with the Assistant Vice PresidentmdashStandards who will be the administrator for the NPCC Regional Standards processDevelopment Procedure and the coordinator of the review and submission of comments to the NERC Reliability Standards


The RSC is responsible for managing the standards process for development of standards VRFs VSLs definitions variances and interpretations in accordance with the NPCC Regional Reliability Standard Process Manual The RSC is responsible for ensuring the quality of all standards related materials

A Management of the NPCC Regional Standards ProcessDevelopment Procedure

The NPCC RSC RSC will consider requests and regulatory directives for new or revised regional standards and be available for to advisement to the NPCC Board BOD on these standards or any standards related matters

The RSC may not itself modify a draft regional standard The RSC will only act on a draft standard in the event of a minor correction such as errata Substantive changes to a draft standard by the drafting team requires issuing a new notice to stakeholders regarding a vote of the modified standard

GZ and LP to work on how to incorporate language to reflect the ability to change VSLs and VRFs to continually adhere to changing FERC and NERC guidelines and requirements

Formatted Space After 18 pt



Formatted Default Space After 0 pt

Page 3 of 5

The RSCrsquos disposition regarding a regional standard authorization request which will in all cases be within 60 calendar days of receipt of a completed standard request shall include(one of the following-requires RSPM revhellip)

bull ACCEPT the standard request as a candidate for development of a new standard revision of an existing standard or cancellation of an existing standard The RSC may at its discretion expand or narrow the scope of the standard request under consideration The RSC shall prioritize the development of standards in relation to other proposed standards as may be required based on the volume of requests and resources

bull REJECT the standard request If the RSC rejects a standard request a written explanation for the rejection will be delivered to the requester within 30 calendar days of the decision

bull REMAND the standard request back to the requester for additional work The Assistant Vice PresidentmdashStandards will make reasonable efforts to assist the requester in addressing the deficiencies identified by the RSC The requester may then re-submit the standard request using the process above The requester may choose to withdraw the standard request from further consideration prior to acceptance by the RSC

The NPCC Regional Standards processDevelopment Procedure responsibilities of the RSC will include

bull Overseeing quality rReview of NPCC Regional Draft Standards for such factors as completeness sufficient detail rational result format and compatibility with existing standards clarifying standard development issues not specified in this procedure Under no circumstance will the RSC change the substance of a draft standardrsquos purpose applicability or requirements

bull Due consideration to the work of the drafting team as well as the comments of stakeholders and minority objections in approving a proposed regional reliability standard to go to ballot (VSL and VRF polling)

bull Approve standards for pre-ballot posting and VSL and VRF polling under a sector based voting structure as described in the NPCC Bylaws or


Provide an oversight role in the development and maintenance of the NPCC Regional Reliability Directories

bull Provide decisions for clarifications

All regional standard related decisional making activities made by the RSC will be approved or rejected by a vote as outlined in the NPCC Bylaws as they pertain to quorum and voting rules

The RSC is responsible for managing the processes for development of NPCC Directories and Criteria The RSC is responsible for ensuring the quality of all directory and criteria

Formatted UnderlineB Management of the NPCC Directory and Criteria Process

Page 4 of 5

related materials

The RSC will be available to advise the NPCC BOD on any directory and criteria related matters

The RSC will

C NERC Reliability Standards

bull Provide NPCC review and coordinate the submission of NPCC comments to existing and developing NERC Reliability Standards when posted for NERC ldquoOpen Process Reviewrdquo

bull Provide a forum for NPCC to participate solicit and provide Regional comments as new Standard Authorization Requests (SARs) and their respective Reliability Standards are developed as part of the NERC Reliability Standards Development Procedure

bull Identify upcoming issues associated with new NERC Reliability Standards and their potential impact to the NPCC Region (ie Regional Difference) Propose solutions or guide the development of the Standards through effective and timely comments and soliciting NPCC participation on the SAR and Reliability Standards drafting teams

bull Develop and maintain a Web-Based Database for tracking and scheduling Standards development activities from a Regional perspective

bull Target a broader range of participation in the commenting process Develop databases and e-mail list servers to engage market participants and different perspectives

bull Develop an entire process for notification solicitation commenting on and revision to Standards

bull Follow up on the NERC Reliability Standards Procedure evolution and provide NPCC members with basic information (or pointers to NERC website) for a common understanding of the process

bull Coordinate activities of NPCC members on standard drafting teams

The RSC will review FERC Orders Rulings and Notice of Proposed Rulemakings (NOPRs) related to reliability standards The RSC will discuss develop comments and if necessary submit the comments to FERC The RSC will coordinate the NPCC response with that of NERC

D FERC Activities Affecting Standards

The RSC will review NERC CANs for reliability standard and compliance implications and submit comments to NERC

E NERC Compliance Application Notices (CANs)

The RSC will

bull Provide NPCC review and submit comments to draft NERC CANs bull Target a broader range of participation in the commenting process

Committee Members

Formatted Space After 18 pt Keep withnext

Formatted Underline



Formatted Highlight

Formatted Underline


Page 5 of 5

Members of the RSC will be elected by the NPCC Board The eight NPCC Sectors as outlined in the NPCC Bylaws each will be represented on the RSC

The RSC will be chaired by an NPCC member of staff who will be acting as the Regional Standards Process Manager with co-vice chairs elected by the RSC from the existing members of the committee at the time the vote is taken Co-vice chairs will serve a term of two years with a one year extension available through a motion and subsequent vote by the committee in accordance with the NPCC Bylaws

Subcommittees and ad hoc Working Groups will be formed at the behest ofupon request of the RSC by NPCC standards program area staff and all associated scopes or charters developed will be approved by the RSC in accordance with the most recent approved and adopted NPCC Bylaws

Formatted Highlight

NPCC Board of Directors Draft for Comment Meeting Minutes February 8 2011

Northeast Power Coordinating Council Inc Board of Directors Meeting Draft Minutes for Comment

February 8 2011 | 830 am NPCC Offices 1040 Avenue of the Americas 10th Floor New York New York The Chairman called to order a duly noticed meeting of the Board of Directors (Board) of Northeast Power Coordinating Council Inc (NPCC) held on February 8 2011 at 830 am A quorum was declared present during the meeting by the President and CEO Edward Schwerdt Andrianne Payson acted as Recording Secretary The meeting announcement agenda and list of attendees are attached as Exhibits A B and C respectively NPCC Antitrust Guidelines The Chairman recommended that a reading of the NPCC Antitrust Guidelines that was distributed via email with the Board agenda package and reviewed by directors upon commencement of the meeting be waived A motion to waive the reading of the NPCC Antitrust Guidelines was duly made seconded and unanimously approved Minutes The President and CEO presented for approval a draft of the minutes of the Board meeting held on December 1 2010 which incorporated all comments received Following discussion the Board agreed that the NERC Matters section of the minutes should be further revised to increase clarification A motion to approve the minutes as revised of the NPCC Board of Directors meeting held on December 1 2010 was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Presidentrsquos Report The President and CEO indicated that the Boards Strategy Meeting yesterday afternoon (February 7) and earlier this morning were worthwhile and that as part of his report to the Board he would highlight the key issues facing NPCC for 2011 and beyond bull During the process of implementing the initiative associated with the development of risk-based

standards it became apparent that there was a lack of common understanding between industry and the regulators as to (i) whether the reliability objective of risk-based standards was to prevent cascading or prevent loss of load and (ii) what constitutes an adequate level of international interconnected bulk power system reliability that appropriately balances costs and benefits to consumers The President and CEO explained that achieving consensus on these fundamental concepts including their applicability to cyber-security related reliability issues was essential to the development of standards with clear performance expectations and accountabilities He further noted that successful efforts to revise the Bulk Electric System (BES) definition and to establish consistent and technically justifiable criteria for BES definition exceptions would be critical to focusing reliability efforts in the future

bull On a procedural level it will be a challenge adapting NPCCs processes to NERCs evolving process for developing reliability standards in order to continue providing Northeast leadership The President and CEO emphasized the importance of maintaining NPCCs leadership role in the standards development process


2

bull Within the Compliance Monitoring and Enforcement Program NERC and the Regional Entities intend to introduce a more risk-based approach to compliance monitoring by considering risk and materiality in the depth and rigor of audits as well as a streamlined administrative citation process for enforcing minor violations The President and CEO explained that this approach would increase the focus on the entities and types of violations that pose the greatest risks to reliability of the bulk power system

bull In connection with the implementation of the revised Regional Delegation Agreement the Regional Entities are working with NERC to build the ERO One Enterprise model with the objectives of enhancing reliability and improving efficiency and effectiveness in working with registered entities The President and CEO noted that NERC and Regional Entity leaders attended a collaborative planning meeting in mid-January to prepare an initial draft of ERO-wide strategic goals through 2015 He explained that these draft goals would be reviewed at the February 16th NERC Member Representatives Committee meeting and that the Boards help me help you message to NERC management would be delivered

bull In connection with the development of NERC and Regional Entity 2012 Business Plans and Budgets NERCs Chief Accounting Officer recently released a preliminary draft of common business planning assumptions that would be reviewed by NERC and the Regional Entities at upcoming meetings next week The President and CEO noted that the purpose of establishing consistent planning goals and assumptions was to promote an enterprise-wide outlook for reliability related activities performed by NERC and the Regional Entities

The President and CEO indicated that he would distribute copies of his remarks to the Board shortly after meetings going forward Membership Category and Sector Designations The President and CEO stated that a Board vote would be required for the sector designations of Maine Public Service Company (General Member) and Groton Electric Light (Full Member) both in Sector 3 (Transmission Dependent Utilities Distribution Companies and Load-Serving Entities) and Penobscot Energy Recovery Company (Full Member) in Sector 4 (Generator Owners) The President and CEO also noted without the requirement for a vote a change in the designation of the Alternate Member Representative for First Wind A motion to approve the sector designations of Maine Public Service Company (General Member) in Sector 3 (Transmission Dependent Utilities Distribution Companies and Load-Serving Entities) Groton Electric Light (Full Member) in Sector 3 (Transmission Dependent Utilities Distribution Companies and Load-Serving Entities) and Penobscot Energy Recovery Company (Full Member) in Sector 4 (Generator Owners) was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Committee Membership Changes The President and CEO informed the Board that there were several changes to NPCCs operating committees

bull Reliability Coordinating Committee ndash Sector 1 (Transmission Owners) (1) Michael Paris to serve as the New York Power Authority alternate replacing Gerald LaRose who recently retired and (2) Michael Schiavone to serve as the National Grid representative replacing Dana Walters Mr Fedora also noted that the RCCs Nominating Committee was currently seeking a new co-Vice Chair for the RCC


3

bull Compliance Committee ndash Sector 1 (Transmission Owners) Michael Bilheimer to serve as the United Illuminating Company alternate

bull Regional Standards Committee ndash Sector 1 (Transmission Owners) Ben Wu to serve as the Orange and Rockland Utilities representative

bull Regional Standards Committee ndash Sector 2 (Reliability Coordinators) Donald Weaver to serve as the New Brunswick System Operator representative replacing Randy MacDonald

A motion to approve these committee changes was duly made seconded and unanimously approved by the Directors in each active Sector of the Board NPCC Committee Reports Regional Standards Committee (RSC) ndash Mr Zito presented the RSC report to the Board which included a discussion of the following (1) there is a draft ballot underway for the draft Underfrequency Load Shedding (UFLS) Regional Standard but quorum has not yet been obtained (2) the RSC is currently reviewing processes to ensure that it can react quickly and more efficiently to any new standards requirements issued by NERC and FERC and (3) the RSC is currently developing a filing for Directories for Nova Scotia and is preparing to do the same for New York State Public Service Commission In response to questions from the Board regarding NPCCrsquos review of NERCs Compliance Application Notice (CANs) postings Mr Buffamante clarified that NERCs CANs are used by compliance auditors to provide guidance while assessing an entitys compliance with reliability standards He noted that NPCC faced the challenge of ensuring that CANs do not change or expand standards requirements Mr Zito then presented the Draft 2011 RSC Work Plan which reflected significant increases in resources that would be required to (i) develop standards including 36 projects of continent-wide standards identified in the NERC Reliability Standards Development Plan 2011-2013 (ii) coordinate NPCCs participation in the revision of CIP standards and (3) assist the Compliance Committee through the development of more auditable requirements in the Phase 2 of the Directories project Board members then suggested that (i) the RSC Work Plan should include an analysis of cost effectiveness of proposed NPCC Regional Standards to convey the seriousness of this issue for NPCC (ii) the RSC reach out to NPCCs GovernmentalRegulatory Affairs Advisory Group to request they advocate for adding an analysis of cost effectiveness as part of the standards development process and (iii) the RSC recommend consolidation of NERC standards projects where appropriate A motion to approve the 2011 RSC Work Plan as revised was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Reliability Coordinating Committee (RCC) ndash Mr Fedora presented the RCC report to the Board which included information on the following (1) the approval of NPCCs long-range adequacy overview (2) endorsement of the NPCC Criteria Compliance and Enforcement Program and (3) the RCCrsquos intent to coordinate the significant increase in written requests for data from NERC The Board then discussed (i) the potential for coordinating reliability metrics data requests from NERC with information developed by the Northeast ISOs (ii) the possible development of a report reflecting the data assembled to date and (iii) the process for transitioning all NPCC criteria (A ldquoBrdquo and ldquoCrdquo Documents) into auditable requirements as appropriate in Regional Reliability Directories by the end of 2011 Mr Fedora then presented the Draft 2011 RCC Work Plan A motion to approve the 2011 RCC Work Plan was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Compliance Committee (CC) ndash Mr Kopman presented the CC report to the Board which included information on the following (1) approval of the Registered Entity Culture of Compliance Survey its initial distribution to 25 entities and the upcoming webinar on February 16 2011 to introduce the survey and answer questions (2) ongoing review of the Compliance Registry and (3) the issuance of 116 compliance

lpedowicz
Highlight
lpedowicz
Highlight


4

violation notices in 2010 (compared with 45 in 2009) and (4)the submission to NERC of mitigation plans associated with these violations (none of which have been rejected by NERC) Mr Buffamante then presented the 2011 Compliance Audit Program which reflects 21 on-site audits scheduled for 2011 11 on-site CIP audits 21 off-site CIP audits and 98 off-site audits (of which two are in progress) He informed the Board that NPCC had received and accepted 423 Technical Feasibility Exception (TFE) submissions to date and that 329 submissions had their Part B substantive assessments completed and approved He noted that NPCC is on schedule to complete assessments of the remaining submissions within a one year period Mr Penstone commended Mr Kopman and the CC for providing the Board with the CMEP metrics table which he found helpful in facilitating the Boards review and evaluation of the CCs work Mr Kopman then presented the Draft 2011 CC Work Plan which reflected the development of more comprehensive performance related to expediting the enforcement process A motion to approve the 2011 CC Work Plan was duly made seconded and unanimously approved by the Directors in each active Sector of the Board MDCC Recommendations The Board Chair reported that the Management Development and Compensation Committee (MDCC) met on January 20 2011 to discuss the 2010 Corporate Goal Attainment Report and the 2010 President and CEO Incentive Compensation Award He stated that the MDCC determined that NPCC had met its 2010 corporate goals and that NPCCs performance with respect to its Regional Entity Division and Criteria Services Division was higher than Meets Target with a composite score of 932 Board members did not have any questions for the President and CEO or the Vice President and COO in connection with the 2010 Corporate Goal Attainment Report However Mr Longhi requested that in the future a scorecard (similar to the CMEP metrics table) be prepared to show measurement of the corporate goals The President and CEO and the Vice President and COO then left the meeting The Board Chair discussed the process by which the MDCC evaluated the overall performance of the President and CEO for 2010 which included a review of the 2010 Exceptional Achievements summary prepared by the President and CEO and supporting detail for each achievement as well as the solicitation of feedback from Board members The Board Chair then distributed copies of draft resolutions with recommendations from the MDCC for Board approval A motion to approve the implementation of a 2010 Variable Incentive Program releasing incentive awards to the NPCC staff to be accrued to the salaries subaccount for 2010 for distribution in early March 2011 was duly made seconded and approved by a majority of the Directors Directors Hans Mertens and Tammy Mitchell in Sector 7 abstained from voting on this motion A motion to approve the implementation of a 2010 Variable Incentive Program releasing an incentive award to the President and CEO to be accrued to the salaries subaccount for 2010 for distribution to the President and CEO in early March 2011 was duly made seconded and approved by a majority of the Directors Directors Hans Mertens and Tammy Mitchell in Sector 7 abstained from voting on this motion The President and CEO and the Vice President and COO then returned to the meeting NPCC 2011 Corporate Goals The President and CEO presented NPCCs Proposed 2011 Corporate Goals to the Board for discussion In response to questions from the Board the President and CEO noted the following (1) the attainment of Bulk Power System revisions would be included in Goal 6a (2) following the issuance of the NERC mid-


5

year report listing certain reliability metrics discussed in Mr Fedoras RCC Report there would be a review of a few key areas for follow-up action (3) the stretch goal for Goal 6a would be revised to reflect FERC approval of a BES filing that contains key provisions that are important to NPCC (4) the corporate goals would be reviewed generally and revised as appropriate to ensure that the development of any draft document is not listed as a stretch goal and (5) each NPCC operating committee should be tasked to develop its own scorecard so the Board can assess the committee work being completed and scorecards should show separate goals relating to improving the efficiency of NPCC as an organization The Board Chair reminded Board members that comments on NPCCs Proposed 2011 Corporate Goals were due on February 18 2011 Organizational Matters CGNC Activities ndash Ms Courville briefly explained the activities of the CGNC in connection with the proposed changes to NPCCs governance structure She then asked Ms Payson to review the proposed changes to NPCCs Amended and Restated Bylaws that are intended to reflect the new governance structure Proposed Bylaw Changes Rules of Procedure for Electing Directors ndash Ms Payson discussed the proposed changes to NPCCs Amended and Restated Bylaws by reviewing the matrix summarizing the revisions to various Bylaw provisions and the Rules of Procedure for Electing Directors The Board provided several comments to the Bylaws and the Rules of Procedure which Ms Payson agreed to revise The Board discussed the proposed timeline for approval of the Amended and Restated Bylaws and agreed to send a complete package of materials to Members containing the mark-up of the Bylaws the matrix summarizing the Bylaw changes and the slide presentation providing an overview of the changes to NPCCs governance structure immediately following the next Board meeting Presentation to Members of NPCC Governance Changes ndash The President and CEO reminded Board members that a draft slide presentation to Members providing an overview of the governance structure changes was discussed during the Board Strategy Meeting on February 7 2011 Report by the Treasurer Mr Weir reported to the Board consistent with the unaudited Statement of Activities for both the Regional Entity and Criteria Services divisions for the period from January 1 2010 through December 31 2010 which had been provided to the NPCC members and Board of Directors in later January by NPCCrsquos Vice President and COO Additionally the Treasurer informed the Board that the independent auditors PricewaterhouseCoopers LLP (PwC) would likely have a draft of NPCCs audited financial statements for 2010 prepared by the end of February He reminded the Board that an unaudited Statement of Activities for 2010 for the Regional Entity Division was required by NERC as are regular quarterly reports and had been previously circulated The Treasurer indicated that NPCCs total expenditures were under budget by nearly $18 million for the year He then asked the Vice President and COO to provide an overview of NPCCs year end results for 2010 The Vice President and COO provided the Board with a breakdown of 2010 funding and comparative expenditure amounts for the total ERO Enterprise (ie NERC and the eight Regional Entities) On an enterprise basis combined funding was nearly$165 million with a variance of more than $10 million She explained that the overall variance as a percentage of total budgeted funding was under budget by 61 She noted that WECC was under budget by less than 1 NERC by 6 FRCC by 18 SPP by 22 and NPCC under by approximately 116 She further noted that total funding was largely on target with the exception of WECC where grant funding was $14 million under budget She then explained that (i) NERCs total funding was over budget by more than $800000 due to increases in fees for system operator


6

tests certificate renewals and continuing education provider fees (ii) NERC and all of the Regional Entities were under budget except for MRO which had added staff to manage processing Technical Feasibility Exceptions (iii) staff for the total ERO enterprise was approximately 98 by year end (iv) meeting expenses on an ERO wide basis were under budget by 24 compared with NPCC which was under budget by 22 (under budget variances ranged from 8 to 44 for this expense) and (v) operating expenses on an ERO wide basis were under budget by 26 or approximately $137 million compared with NPCCs under budget of 14 due mainly to lower fees and expenses for consultants professional services and legal fees She noted that NPCCs Criteria Services Division similar to the Regional Entity Division was also under budget by 42 or $463240 for 2010 The Vice President and COO informed the Directors that a NERC teleconference for its Finance and Audit Committee was being held tomorrow (February 9) where concerns would likely be expressed as to whether a Regional Entitys under spending could be viewed as underperformance of that entitys Regional Delegation Agreement (RDA) and that while expenditures were under budget NPCC would indicate that all requirements under the RDA were met during 2010 Regulatory Matters Mr Fedora provided an update of revisions to the BES definition He noted that the first meeting of the BES standard drafting team would be held on February 9-11 2011 and that he would circulate unofficial summary notes to the Board within one week after drafting team meetings NERC Matters The Board Chair noted that the meetings of the NERC Member Representatives Committee and the NERC Board of Trustees were scheduled for February 16 and 17 2011 respectively The President and CEO explained that Board policy input was requested for four items (1) ERO Enterprise Strategic Direction (2) Bulk Electric System Definition-Policy Issues and Questions (3) Priorities for Addressing Risks to Reliability and (4) Alerts and the Alerts Process Following Board discussion the President and CEO agreed to revise the draft Board Policy Input to clarify certain comments and to include recommendations for (i) any proposed implementation strategy for the BES definition to include an adequate transition period incorporating cost-effective modifications into the schedules for system modifications and (ii) the expansion of Issue 6 Integration of New Technologies to reflect a working partnership among manufacturers providers and public policy makers in order to achieve the desired reliable integration A motion to approve the draft Board Policy Input subject to revisions by the President and CEO was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Administrative Matters The Board Chair reminded Board members that all Directors needed to execute the Annual Code of Conduct Implementation Agreement Other Matters Mr Haake informed the Board that he would be leaving Dynegy at the beginning of April 2011 and this would be his last Board meeting The President and CEO then informed the Board that Mr Janega had changed roles within Nova Scotia and planned to resign from the Board shortly Mr Mertens requested that Resolutions of Appreciation be prepared for both Mr Haake and Mr Janega for their efforts and contributions to the Board A motion directing the President and CEO to prepare Resolutions of Appreciation for Mr Haake and Mr Janega was duly made seconded and approved by a majority of the Directors Mr Haake abstained from voting on this motion


7

Future Meetings The President and CEO presented the schedule of Board meetings for the remainder of calendar year 2011 which was distributed via email with the Board agenda package Adjournment There being no further business the Chairman adjourned the meeting of the NPCC Board of Directors at 1240 pm Approved by Board action on _______________ 2011 Submitted by ______________________ Andrianne S Payson NPCC Secretary


8

EXHIBIT C LIST OF ATTENDEES

February 8 2011

Present Harvey J Reed Chairman Edward A Schwerdt President and CEO Jennifer Budd Mattiello Vice President and COO Christopher Weir CPA Treasurer Andrianne S Payson Esq Secretary And the following members of the Board of Directors Sector 1 (TOs) William G Longhi Orange amp Rockland Utilities

Isabelle Courville Hydro-Queacutebec TransEacutenergie (by teleconference)

Sector 2 (RCs) Peter Brandien ISO New England Inc Bruce B Campbell Independent Electricity System Operator Rick Gonzales New York Independent System Operator Inc (via proxy to President)

Sector 3 (TDUs DCs LSEs)

Douglas McCracken National Grid Michael Penstone Hydro One

Sector 4 (GOs) Glenn D Haake Dynegy Andrew Barrett Ontario Power Generation Inc Rick Janega Nova Scotia Power Inc (via proxy to President)

Sector 5 (Marketers Brokers and Aggregators)

Glen McCartney Constellation Energy Commodities Group Inc Matthew J Picardi Shell Energy NA (via proxy to President) Daniel Whyte Brookfield Power Generation

Sector 6 (Customers) ndash

Sector 7 (Regulatory) Hans Mertens Vermont Department of Public Service Tammy Mitchell NYS Department of Public Service

Sector 8 (Others) Michael Forte New York State Reliability Council LLC Guests Wes Yeoman New York Independent System Operator

Guy V Zito NPCC Assistant Vice President ndash Standards Stanley Kopman NPCC Assistant Vice President ndash Compliance Enforcement Philip Fedora NPCC Assistant Vice President ndash Reliability Services Salvatore Buffamante NPCC Assistant Vice President ndash Compliance Audits and Investigations

- 1 - LRP 312011 1027 AM


NPCC Regional Standards Committee Draft Minutes for Approval

Meeting 11-1

February 2 2011 1000 am - 500 pm (severe weather)

February 3 2011 800 am - 300 pm

NPCC Offices 1040 Avenue of the Americas

10th Floor New York New York



Items in red from Feb 2 2011 Items in green from Feb 3 2011

1 Introductions-Agenda Review-Roster a RSC membership changes Randy MacDonald (New Brunswick System Operator) moved from Sector 2 (Reliability Coordinators) to Sector 1 (Transmission Owners) Donald Weaver (New Brunswick System Operator) will replace Randy MacDonald in Sector 2 Ben Wu (Orange and Rockland Utilities Inc) will join

- 2 - LRP 312011 1027 AM

the RSC in Sector 1 Both memberships on the agenda for the Feb 8 2011 NPCC Board of Directors Meeting Wayne Sipperly (NYPA) new member (Sector 4--Generator Owner) Kal Ayoub has been promoted to Manager Reliability Standards at FERC Attendees

Name Organization Sector 1 Michael R Lombardi Northeast Utilities 1 2 Si Truc Phan Hydro-Quebec TransEnergie 2 3 Brian Gooder Ontario Power Generation Incorporated 4 4 Saurabh Saksena National Grid 3 5 Chris de Graffenried Consolidated Edison Co of New York Inc 1 6 Brian Evans-Mongeon Utility Services 5 7 Gerry Dunbar Northeast Power Coordinating Council 8 Randy MacDonald New Brunswick System Operator 1 9 Lee Pedowicz Northeast Power Coordinating Council 10 Guy Zito Northeast Power Coordinating Council 11 Bruce Metruck New York Power Authority 5 12 Wayne Sipperly New York Power Authority 4 13 Kal Ayoub (guest) FERC 14 Ben Wu (guest) Orange and Rockland Utilities Inc 1

On the Phone (Webex made available)

Name Organization Sector 1 Kurtis Chong Independent Electricity System Operator 2 2 Sylvain Clermont Hydro-Quebec TransEnergie 1 3 Ron Falsetti (guest) AESI (consultant) 4 Kathleen Goodman ISO - New England 2 5 David Kiguel Hydro One Networks Inc 1 6 Mike Garton Dominion Resources Services Inc 4 7 Diane Barney New York State Department of Public Service 7 8 Bohdan Dackow US Power Generating Company (USPG) 4 9 Greg Campoli New York Independent System Operator 2 10 Ronnie Epstein (guest) New York Power Authority 11 Donald Weaver (guest) New Brunswick System Operator 2

Guy Zito discussed the addition of Agenda Items 9c 21e 21f and 23 (Directory Development Manual)

- 3 - LRP 312011 1027 AM

2 RSC November-December 2010 Meeting Minute Approval and Antitrust Guidelines (in Meeting Materials Package) a Includes December 2 2010 joint meeting with the Compliance Committee Lee Pedowicz read the Antitrust Compliance Guidelines at the outset of the meeting David Kiguel and Randy MacDonald made changes to the Meeting Minutes Michael R Lombardi made a motion to approve the Minutes as revised Seconded by Chris de Graffenried All members present with the exception of Bruce Metruck voted to approve Bruce Metruck abstained


Package) (Refer to table at the back of Agenda) a NPCC Members on NERC Drafting Teams

Saurabh Saksena to maintain He will get updates from Carol Sedewitz

4 Review Executive Tracking Summary (in Meeting Materials Package) a Review entries

Michael R Lombardi was thanked for the work he has put into revising and maintaining the Executive Tracking Summary It is still a work in progress and it will ultimately provide ldquoone stop shoppingrdquo for RSC information There is a button on the RSC home page that takes you to the Executive Tracking Summary David Kiguel commented that it would be beneficial to access earlier versions of the Executive Tracking summary and histories of documents Saurabh Saksena discussed combining the Executive Tracking Summary with the NPCC members on NERC Drafting Teams Guy Zito expressed a desire not to do it because it would expose individualsrsquo information Guy Zito reported that on the new NPCC Website being developed (that is scheduled to be tested in March) the need for archiving will be considered

5 FERC (in Meeting Materials Package) a December 2010 Meeting Summaries

Guy Zito discussed b January 2011 Meeting Summaries

Guy Zito discussed Guy Zito proposed establishing a RSC team to develop a response to NOPRs

- 4 - LRP 312011 1027 AM

Lee Pedowicz to make a table for this item that will include the effective date the Docket Number and any other pertinent information from a posting

c Federal Register 1 Mandatory Reliability Standards for Interconnection Reliability

Operating Limits 2 System Restoration Reliability Standards 3 Revision to Electric Reliability Organization Definition of Bulk Electric

System a Request for Rehearing of the New York State Public Service

Commission of Docket No RM09-18-000 - Revision to Electric Reliability Organization Definition of Bulk Electric System

The Standards Committee had a meeting last month Brian Evans-Mongeon and Phil Fedora (NPCC) are on the Drafting Team et al are NPCC representatives on the Drafting Team The exception process is going to have to be dealt with This will depend on the comments received from the SAR posting and could result in having to dedicate resources to do studies The scope is being increased Sylvain Clermont commented that he discussed the exception process with Herb Schrayshuen A working group within NERC will be put together to look at the exception process Will also have to deal with NERC Rules and Procedures The working group will consist of stakeholders as well as NERC Staff Itrsquos not known if this will be a ldquoformalrdquo working group Brian Evans-Mongeon reported that there is a meeting next week and there is room for twenty five observers Elizabeth Crouch had sent out the notice If you signed up to be an observer yoursquod have to be physically at the meeting There were 199 pages of comments submitted for the Exception Process The Drafting Team hasnrsquot seen the comments for the Bulk Electric System definition Brian Evans-Mongeon forwarded the E-mail that contained the announcement for observers Chris de Graffenried commented that there is a jurisdiction issue that FERC and NERC donrsquot recognize Canadian Provinces are not being considered

4 System Personnel Training Reliability Standards For information only

5 Interpretation of Protection System Reliability Standard Comments on the NOPR are due Feb 25 2011

6 Version One Regional Reliability Standard for Transmission Operations Concerned with WECC

7 For information compliance filing of Proposed Violation Risk Factors and Violation Severity Levels for Available Transfer Capability Reliability Standards

8 Priorities for Addressing Risks to the Reliability of the Bulk- Power System

9 Electric Reliability Organization Interpretations of Interconnection Reliability Operations and Coordination and Transmission Operations Reliability Standards

10 Version One Regional Reliability Standards for Facilities Design Connections and Maintenance Protection and Control and Voltage

- 5 - LRP 312011 1027 AM

and Reactive Concerned with WECC


a

Project 2010-13 - Relay Loadability Order - PRC-023 PRC-023-2 Redline to last posting PRC-023-2 Redline to last approval Implementation Plan Redline to last posting VRFVSL Justification Mapping Document Announcement


Non-Binding Poll

012411 021311

b

Project 2010-11 - TPL Table 1 Order Implementation Plan TPL-001-1 Redline to last posting TPL-001-1 Redline to last approval TPL-002-1b Redline to last posting TPL-002-1b Redline to last approval TPL-003-1a Redline to last posting TPL-003-1a Redline to last approval TPL-004-1 Redline to last posting TPL-004-1 Redline to last approval Announcement

Recirculation Ballot 012611 020511

Item 6a--Kurtis Chong sent his comments to the group The meeting attendees agreed with his comments Item 6b--This Recirculation Ballot will be the last ballot Discussion ensued over the grouprsquos understanding of the footnote

- 6 - LRP 312011 1027 AM


a


COM-001-2 Redline to last posting Implementation Plan Redline to last posting COM-002-3 Redline to last posting Implementation Plan Redline to last posting IRO-001-2 Redline to last posting Implementation Plan Redline to last posting IRO-005-2 Redline to last posting Implementation Plan Redline to last posting IRO-014-2 Redline to last posting Implementation Plan Redline to last posting Comment Form (link to Word version) Announcement (initial Announcement) Announcement (latest with extension)

Comment Form

011811

030711


Join Ballot Pool 012511 022511

b

Project 2007-23 - Violation Severity Levels VSLs Redline to last Approval Comment Form (link to Word Version) Announcement

Comment Form

012011 021811

Non-Binding Poll

020911 021811

Join Ballot Pool

012011 020911

c

Project 2007-07 - Vegetation Management - FAC-003 FAC-003-2 Redline to Last Posting Implementation Plan Redline to Last Posting FAC-003-1 Comment Form (link to Word Version) Technical White Paper Redline to Last Posting

Comment Form

012711 022811


Non-Binding Poll

021811 022811

- 7 - LRP 312011 1027 AM

Announcement

Item 7a--It was noted that the ballot starts Feb 25 2011 It appears to be restricted to emergency communications Kathleen Goodman to send comments to the RSC for their consideration Some historical information offered was that a Request for Interpretation had been submitted on clarification of three part communication The RSC didnrsquot think three part communication was needed for everything The Request for Interpretation was submitted about two years ago There was a bulletin issued that stipulated that communications be three part Kathleen Goodman got no response Kathleen Goodman will be asking the Standards Committee for a status She will also send the comments that shersquoll be submitting to the IRC to the group Item 7b--Kurtis Chong discussed the IESOrsquos response to question 2 on the Comment Form Kurtis Chong to reformat the response in the form of a comment Kurtis Chong will redo the Comment Form and submit to the group Item 7c--A recommendation for the vote is needed by Feb 18 2011 Chris de Graffenried reported that Con Edisonrsquos subject matter expert suggests voting ldquoforrdquo Guy Zito told the assembled that members with overhead transmission lines should have their subject matter experts review 8 Join Ballot Pools (in Meeting Materials Package)


a

Regional Reliability Standards - PRC-006-NPCC-1 - Automatic Underfrequency Load Shedding

Comment Form (link to Word version) PRC-006-NPCC-1 Implementation Plan


b

Standards Committee Project Prioritization Tool Standards Committee Project Prioritization

Worksheet (link to Excel Spreadsheet)

Informal Comment Period 012111 021011

- 8 - LRP 312011 1027 AM

Standards Committee Reference Document for

Project Comment Form (link to Word Version) Announcement

Item 9a--This Regional Standard is going back to the Drafting Team See Item 21b1a below Kurtis Chong inquired as to why there was no quorum on the ballot for the Standard Guy Zito replied that NPCC did everything it could to get the members to vote David Kiguel brought up that NERC had ldquoticklersrdquo for balloted items Item 9b--This item was discussed earlier It will probably be approved by the NERC Board of Trustees There are a lot of open questions Guy Zito reported that this is going to be used by the Standards Committee for input to the Work Plan Brian Evans-Mongeon commented that it is still very subjective Chris de Graffenried discussed his comments Item 9c--(independent of above table)--How can the RSC be more efficient with successive ballots and all the concurrent activities taking place Guy Zito suggested the necessity of having more frequent meetings of the Executive Committee set up sub-groups within the RSC Guy Zito is trying to get a skill set of the NPCC employees to identify those that can assist with comment submissions Guy Zito is seeking observations from the participants Need to have better Task Force cooperation Better notifications would make the process more efficient and improve the cooperation of the Task Forces This should be brought to the attention of the RCC Kurtis Chong commented that when NERC makes postings on a Friday for a ten day comment period it includes two weekends It was suggested that an improvement would be to post on a Monday or a Tuesday so there is only one weekend in the comment period Guy Zito said that the Standards Committee will be informed that regional standards arenrsquot posted in the right places on the NERC Website Guy Zito reported that April 1 Stephanie Monzon (NERC) will be leaving her present standards assignment in NERC to go work for Tom Calloway (NERC) Guy Zito requested that RSC members send him their thoughts 10 Reference Documents Posted For Comment

a

- 9 - LRP 312011 1027 AM

11 Concluded Ballots (in Meeting Materials Package)

httpsstandardsnercnetBallotsaspx (clicking in the ldquoBallotrdquo column links to the Ballot Results)

Results of Ballot

RSC RecommendDate

a Project 2010-13 - Relay Loadability

Order Initial Ballot 120710 121610

Quorum--8800 Appd--5151

No 121010

b

Project 2007-04 - Certifying System Operators - PER-003


120210 121310


Yes 91410

c Project 2010-15 - Urgent Action

Revisions to CIP-005-3

Initial Ballot and Non-

Binding Poll 120210 121110

Quorum-- 8446 Appd--

4289

No 12810

d

Project 2008-06 - Cyber Security - Order 706 - CIP-002 through CIP-009

Successive Ballot

120110 121010

Quorum-- 8707 Appd-- 7706

No Consensus

e

Project 2007-17 - Protection System Maintenance amp Testing

Successive Ballot

121010 121910


Yes 10410

Non-binding Poll for VRFs

and VSLs 121010 121910

Quorum--7806

Supportive Opinion--5273

f

Project 2009-17 - Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State GampT


112910 12310


Yes RSC Meeting

113010

g



122010 123010


Yes 11210

h Project 2010-10 - FAC Order 729 Successive Ballot

123010 010811


Yes 10511

i Project 2010-11 - TPL Table 1 Order Initial Ballot 122710 010511

Quorum--9042 Appd--

Yes 10511

- 10 - LRP 312011 1027 AM

8333

k Project 2010-10 - FAC Order 729 Recirculation

Ballot 011411 012311


Yes 10511

Item 11k--FAC-013-2 its Implementation Plan and new definitions adopted and its

VRFs and VSLs approved approved by the NERC Board of Trustees Jan 24 2011 These documents will be filed for regulatory approval by Jan 28 2011

This added section provides good information and will be included in future agendas 12 Posted For 30-Day Pre-Ballot Review (Open Ballot Pools) Between RSC

Meetings

a


a Project 2008-06 - Cyber Security - Order 706 - CIP-002

through CIP-009 Comment

Form 120110 121010

b Project 2010-11 - TPL Table 1 Order Comment Form

111910 10511

c Project 2009-22 - Interpretation of COM-002-2 R2 by

the IRC Comment

Form 111810 121810

d Project 2007-17 - Protection System Maintenance and

Testing - PRC-005 Comment

Form 111710 121710

e Project 2010-15 - Urgent Action Revisions to CIP-005-3

- CIP-005 Comment

Form 111210 121110

f Project 2010-13 - Relay Loadability Order - PRC-023 Comment

Form 110110 121610

g Project 2010-16 - Definition of System Operator Comment Form

110310 120310

h Project 2010-10 - FAC Order 729 Comment

Form 121010 10811

i Project 2010-17 - Definition of Bulk Electric System Comment Form

121710 012111

j Resources Subcommittee White Paper on Frequency

Response Comments 1210 020111

- 11 - LRP 312011 1027 AM


a


a Project 2010-17 - Definition of Bulk Electric System Nomination

Form 121710 010411

16 NERC Meetings (in Meeting Materials Package) a ERO-RAPA b MRC and BOT Meetings 17 NERC RSG RRSWG (in Meeting Materials Package) a Update The RSG will be replacing the RRSWG The RSG will strive to achieve uniformity between regions

18 Standards Committee Report (in Meeting Materials Package) a Dec 8 2010 Meeting

At its January Meeting the Bulk Electric System Drafting Team was selected Regional Standards will be given a Quality Review--legal technical writer NERC will have a Quality Review Team for postings The review will be conducted before a ballot and the Quality Review Working Group will include a legal review It has been speculated that this review will lengthen the process

19 SCPS Meeting

Guy Zito and David Kiguel are on the SCPS Involved with the NERC processes The Standards Prioritization Project originated in this group

20 NERC Compliance Application Notices a Comments to the CAN process

Guy Zitorsquos comments from the joint meeting with the CC in December 2010 It was thought that the CAN process was closed Stan Kopman was to be the RSCrsquos conduit for comments Subsequent to the joint meeting the request for comments was made public Guy Zito to talk to Stan Kopman about how CANs will be dealt with in the future CANs 15 16 and 18 were sent out

- 12 - LRP 312011 1027 AM

David Kiguel reminded the participants to send in their responses to CANs 12 and 13 Brian Evans-Mongeon commented on a possible ldquotriagerdquo for CANs and Guy Zito stressed the need for a coordinated review of CANs This will be considered as the RSC Scope is developed

21 NPCC Regional Standards--Update (in Meeting Materials Package) a Disturbance Monitoring (PRC-002-NPCC-01)

1 VSLs approved by NPCC membership NERC Board of Trustees approved Nov 4 2010 Being prepared for FERC and Canadian entity filings



a Ten day ballot concluded on Jan 28 2011 Did not get quorum RSC to remand back to Drafting Team

c Special Protection System d Regional Reserve Sharing 1 Draft RSAR developed 2 TFCO soliciting for members


a Status of the filing Compliance Attorney looking at Phase 1 of the Directories Expect report in two weeks

23 Directory and Regional Work Plan Status Directory Number


Current Activity


Approved on 1212009

TFCP has charged CP11 with a comprehensive review of Directory 1 to include the triennial document review and an examination of the NERC TPL standards the existing NPCC planning criteria and the implementation of Phase 2 of the Directory Project which will reformat existing Directory criteria into NERC style requirements CP11 expects to present a first draft of the reformatted Directory 1 to TFCP and other Task Forces at the TFCP Meeting on Feb 9 2011 for comments CP11rsquos initial schedule called for presenting a final draft to RCC in November 2011


Approved on 102108



Approved on 71108


- 13 - LRP 312011 1027 AM


Approved on 12109



TFCO Directory5 was approved by the Full Members on December 2 2010 TFCO working to resolve outstanding reserve issues associated with Directory 5 TFCO expects to post a revised version of Directory 5 to the Open Process after their February meeting

7 (A-11)


Approved on 122707


8 (A-12)

System Restoration

Approved on 102108


9 (A-13)


Approved on 122208

TFCO to consider draft language that would revise section 70 to ensure that documentation is not sent to TFCO The next TFCO review is scheduled for July 2012


Approved on 122208



Approved on 62609


X Reserve Sharing

TFCO TFCO considering draft of a new Directory on Regional Reserve Sharing which would replace C38 until a Regional Standard is developed TFCO expects to post draft of Directory X after the TFCO meeting in February

Phase 1 of the Directory Project the initial translation of criteria completed December 2010 Directory 5 was the last Directory approved RCC told TFCO to continue working on Directory 5 to resolve outstanding issues TFCO is also working on a new Directory for Regional Reserve Sharing TFCO hopes to have a draft ready for posting this spring (TFCO also has the Regional Standard on Regional Reserve Sharing) Phase 2 is underway with the reformatting of Directory 1 A Directory Development Manual is to be developed this year Developing a new NPCC Glossary of Terms is also being considered The goal is to complete Phase 2 this year and to make the Directories a real requirement

- 14 - LRP 312011 1027 AM

24 Review RFC MRO Standards Relevant to NPCC (in Meeting Materials Package)

a RFC Standards Under Development webpage httpsrsvprfirstorgdefaultaspx

b RFC Standard Voting Process (RSVP) webpage ReliabilityFirst Corporation - Reliability Standards Voting Process MOD-025-RFC-01 - Verification and Data Reporting of Generator Gross

and Net Reactive Power Capability passed its 15 day Category vote Anticipated RFC Board of Directors action to approve to approve during their March 3 2011 meeting

Standard Under


1

PRC-006-RFC-01 - Automatic Under Frequency Load Shedding Requirements

Post Comment 011211 021011

2





Adding this item to the RSC Scope to be considered A suggestion was made to make this item for information only and only when the documents listed are posted at NERC





2

- 15 - LRP 312011 1027 AM

25 Report on NERC NAESB and Regional Activities (in Meeting Materials Package)

a Report on NERC NAESB and Regional Activities 1

Lee Pedowicz to continue calling in

26 Task Force Assignments If any members want to be added to the Regional Reserve Sharing Drafting Team let Guy Zito or Lee Pedowicz know 27 Future Meetings and Other Issues (in Meeting Materials Package)

a RSC--Procedure For Handling Comments To NERC Revise procedure to better handle received comments for consensus Consider NERCrsquos latest comment issuance and resolution procedures

b NERC NPCC--Reliability Standards filed with the Nova Scotia Utility Review Board (UARB) for approval

1 Nova Scotia Information Requests for filing NPCC Criteria c Proposed Amendments To NERC Rules Of Procedure Section 300

Comments Of The Canadian Electricity Association d NERC Newsletter 1 December 2010 2 January 2011 e Link to SERC httpserccentraldesktopcomstandardhomepagedoc10275904amppgref f NERC Compliance Application Notices Guy Zito mentioned that someone needs to evaluate CANs and if it is felt

that it is needed it should be brought to the RSCrsquos attention g NERC Drafting Team vacancies

Item 27a--Lee Pedowicz is going to review and consider changing the process to more effectively capture the RSC consensus opinion Kathleen Goodman suggested incorporating a ldquodrop deadrdquo deadline to encourage timely submission of comments Other options to consider are the selective issuance to Task Forces of materials posted for comments and have a greater utilization of conference calls Suggested that when Lee Pedowicz sends out a Meeting Materials posting notification (prior to RSC Meetings) state in the transmittal that any Comment Forms will have a ldquodrop deadrdquo deadline at the RSC Meeting or at a conference call whichever is applicable Comments received late will still be issued to the RSC for informational purposes Item 27b--Informational item Item 27c--Sylvain Clermont submitted comments that specifically related to FERC Directives

- 16 - LRP 312011 1027 AM

Item 27d--Informational item Item 27e--SERC changed their home page Item 27f--discussed under Item 20 above Item 27g--For information

It was mentioned the New Brunswick automatically accepts NERC criteria Meeting adjourned 1639 on Feb 2 2011

Guy Zito opened the Feb 3 2011 session with a request for any additional items to discuss There was a discussion of NERC Successive Ballots Brian Evans-Mongeon said that regarding EOP-004 a document is being prepared to be posted for a comment period 225 pages of comments had been received Revisions made to reflect those comments Expected to go to the NERC Board of Trustees in the May-June timeframe Formal comments will be solicited in the March-April timeframe The RSC November Meeting dates have to be changed because of a conflict with the NPCC Annual and General Meetings Meeting adjourned 1221 Feb 3 2011


March 16-17 2011 Richmond Virginia

October 19-20 2011 Burlington Vermont




- 17 - LRP 312011 1027 AM


Feb 18 2011 July 15 2011 March 4 2011 August 19 2011 April 1 2011 Sept 2 2011 April 15 2011 Sept 16 2011 April 29 2011 Sept 30 2011 May 13 2011 Oct 28 2011 June 3 2011 Nov 10 2011 (Thursday) June 17 2011 Dec 16 2011 July 1 2011 Dec 30 2011


February 7-8 2011 NPCC July 28 2011 Teleconference March 15 2011 Teleconference on Bylaws September 20 2011 NPCC

May 3 2011 Teleconference October 26 2011 Teleconference June 30 2011 NPCC November 30 2011 Toronto


RCC March 3 June 1 Sept 8 Nov 29 CC Feb 15 April 13 May 16 June 14-15

July 13 August 17 Sept 21-22 Oct 19 Nov 16 Dec 13-15

TFSS Jan 20-21 TFCP Feb 9 May 11 August 17 Nov 2 TFCO Feb 24-25 April 14-15 August 11-12

Oct 6-7 TFIST TFSP Jan 18-20 March 22-24 May 24-26 July

19-21 Sept 27-29 Nov 15-17

Respectfully Submitted Guy V Zito Chair RSC Assistant Vice President-Standards Northeast Power Coordinating Council Inc

- 18 - LRP 312011 1027 AM

Northeast Power Coordinating Council Inc (NPCC) Antitrust Compliance Guidelines






competitor


- 19 - LRP 312011 1027 AM

Action Item List

Action Item

Number

Agenda Item


32 16b To discuss with Jerry Adamski how HQ because of its unique operational requirements will be addressed in standards development


RSC Meeting








Feb 17-18 2009

June 17-18 2009

August 6-7 2009



Ongoing

61 21 Notify NPCC Drafting Team members that the RSC is available for advice at any time and that they will be invited to call in with status reports


Ongoing

- 20 - LRP 312011 1027 AM

Action Item

Number

Agenda Item


Sept 24-25 2009

Nov 4-5 2009

April 21-22 2010




session April 21 2010 Ongoing There will be a joint RSCCC

Meeting in December Ralph Rufrano will be

rejoining the RSC in the capacity of

NPCC Compliance liaison Comments not to be submitted

on the CCEP June 29-30 2010


NPCC Members on NERC Drafting Teams list and provide David Kiguel with updates Lee Pedowicz sent E-mail to update individual memberrsquos status

RSC RSC Meeting

Ongoing

- 21 - LRP 312011 1027 AM

Action Item

Number

Agenda Item


August 18-19 2010



Provide update



RSC Meeting


Nov 30 2010 Dec 2 2010



RSC Meeting



Feb 2-3 2011

70 20 Talk to Stan Kopman and the CC about the process for submitting comments after Valerie Agnew (NERC) drafts CANs for their first posting Industry will have two weeks for


RSC Meeting

- 22 - LRP 312011 1027 AM

Action Item

Number

Agenda Item


comments 71 Talk to Compliance

about Reliability Standard RSAWs There should be a Compliance Committee representative on the Drafting Team

Guy Zito RSC meeting

72 Find out what other

Regions are doing regarding interpretations


73 Discuss consistency

with the RSG Guy Zito RSC

Meeting

Action Item 68--Guy Zito Lee Pedowicz Chris de Graffenried and Michael Lombardi worked on making a revision to the Regional Reliability Standards Development Procedure Guy Zito sought volunteers to review the document with the changes made Brian Gooder and Kurtis Chong volunteered and will review by mid-February The RSAW process should minimize the number of documents that when changed have to go to the Board for approval Will go in the NPCC Open Process and at NERC for approval Does the NPCC membership have to approve Action Item 69--The question was raised whether NERC Alerts should be included David Kiguel said that there are different levels of Alerts The distribution of Alerts is determined by the entity types The RSC apparently wouldnrsquot get everything Even though all Sectors are represented the representatives arenrsquot necessarily the ones receiving the Alerts Guy Zito--Eventually there will be a Regional Standard process for review of Standards and Criteria Guy Zito--Will present revised Scope ideas to the NPCC Board of Directors at their May 3 2011 Meeting (teleconference)

- 23 - LRP 312011 1027 AM

Guy Zito--NPCC organization changing from an eight sector membership to a six sector membership The Board of Directors will have a hybrid makeup The Small Customer Sector is being eliminated Guy Zito Lee Pedowicz and Michael Lombardi will work on the RSC Scope After a draft completed will distribute to the RSC Saurabh Saksena asked whether the Scope will include the review of other Regionrsquos standards RSC will stop doing it Chris de Graffenried commented that the RSC should be comparing similar regional standards Guy Zito--Presented the idea to the members of the RSC taking on more responsibility and authority

Page 1 of 3

Revised 3102011

Line No Project No TitleHigh

Priority Associated Standard SAR PostedPosted for Comment

Posted For Ballot

Industry Approved

NERC BOT Approved

Petitioned for FERC Approval FERC Approved Comments Project Status

1 Project 2006-01 ― System Personnel Training No PER-004-2 and PER-005-1Yes 2nd (Thru

32006)Yes 4th (Thru

71708)Yes 5th (Recirc Thru 122208) Yes (122208) Yes (040109) Yes (93009) Yes (111810) Completed

2 Project 2007-05 ― Balancing Authority Controls No NA NA NA NA NA NA NA NA

As of July 28 2010 this project has been merged with Project 2007-18 - Reliability-based Controls and is now Project 2010-14 - Balancing Authority Reliability-based Control NA

3 Project 2007-18 ― Reliability-based Control No NA NA NA NA NA NA NA NA


4 Project 2007-24 - Interpretation of TPL-002 and TPL-003 No TPL-002-0a and TPL-003-0a x xYes 2nd (Thru

7708) Yes ( 7708) Yes (73008) Yes (102408) Yes (42310) Completed

5 Project 2008-06 ― Cyber Security ― Order 706 (VRFs and VSLs) No CIP VRFs and VSLs xYes 1st (Thru

42009)Yes (Recirc Thru

111209) Yes (111209) Yes (121609) Yes (121809) Yes (12011) Completed

6 Project 2008-07 ― Interpretation of EOP-002-2 R63 and R71 by Brookfield Power No EOP-002-2 R63 and R71 x xYes (Recirc Thru

83109) Yes (83109)No (Remanded

21610) NA NA

21610 NERC BOT(1) Remands the proposed interpretation of EOP-002-2 Requirements R63 and R71 to the Standards Committee because the proposed interpretation adds requirements not in the standard thereby exceeding the permissible scope of an interpretation and(2) Directs the Standards Committee to initiate action to revise EOP-002-2 as appropriate NA

7 Project 2008-11 ― Interpretation of VAR-002a by ICF Consulting No VAR-002-11b x xYes (Recirc Thru


8 Project 2009-08 ― Nuclear Plant Interface Coordination No NUC-001-2Yes 1st (Thru

31809)Yes 1st (Thru


72009) Yes (72009) Yes (8509) Date Yes (12110) Completed

9 Project 2009-13 ― interpretation of CIP-006-1 by PacifiCorp No CIP-006-2c x xYes (Recirc Thru


10Project 2009-15 ― Interpretation of MOD-001-1 R2 and R8 and MOD-029-1 R5 and R6 by NYISO No MOD-001-1 R2 and R8 and MOD-029-1 R5 and R6 x x

Yes (Recirc Thru 71709) Yes (71709) Yes (11509) Yes (12209) Yes (91610) Completed

11Project 2009-16 mdash Interpretation minus CIP-007-1 R2 mdash Systems Security Management No CIP-007-2a x x

Yes (Intitial Thru 92109) Yes (92109) Yes (11509) Yes (111709) Yes (31810) Completed

12 Project 2009-18 ― Withdraw Three Midwest ISO Waivers No BAL-006-2 and INT-003-3 x xYes (Intitial Thru


13Project 2009-21 ― Cyber Security Ninety-day Response ― CIP Family of Standards No CIP-002 through CIP-009 V3

Yes 1st (Thru 111209)


Yes (Recirc Thru 121409) Yes (121409) Yes Yes (11910) Yes (31810) Completed

14 Project 2010-12 ― Order 693 Directives NoBAL-002-1 EOP-002-3 FAC-002-1 MOD-021-1 PRC-004-2 and VAR-001-2



Yes 2nd (Recirc Thru 73110) Yes (73110) Yes (8510) Yes (9910) Yes (11011) Completed

15 Pre-2006 ― Operate Within Interconnection Reliability Operating Limits No IRO-008-1 IRO-009-1 and IRO-010-1aYes 2nd (Thru

92302)Yes 9th (Thru

42508)Yes 1st (Recirc Thru 82108) Yes (82108) Yes (101708) Yes (123109) NOPR issued 111810 - Comments were due 12411 Pending Regulatory Approval

16 Project 2006-03 ― System Restoration and Blackstart No EOP-001-2 EOP-005-2 and EOP-006-2Yes 2nd (Thru

30907)Yes 4 th (Thru

111808)Yes 5th (Recirc Thru 51809) Yes (51809) Yes (8509) Yes (123109) NOPR issued 111810 - Comments were due 12411 Pending Regulatory Approval

17 Project 2006-04 ― Backup Facilities No EOP-008-1Yes 2nd (Thru

31607)Yes 5th (Thru

3810)Yes 7th (Recirc Thru 72610) Yes (72610) Yes (85010) Yes (21111) Pending Regulatory Approval

18 Project 2006-08 ― Transmission Loading Relief No IRO-006-5 and IRO-006-East-1

Yes (For DT Nomination

11207)Yes 4th (Thru

113009)Yes 6th (Recirc Thru 83010) Yes (83010) Yes (11410) Yes (11311) Pending Regulatory Filing

19 Project 2007-27 ― Interpretation of CIP-006 R11 by SCEampG No CIP-006 R11 x xYes (Recirc Thru

12407) Yes (12407) Yes (21208) Yes (122209) Pending Regulatory Approval

20 Project 2008-06 ― Cyber Security ― Order 706 (CIP-002-4) Yes CIP-002-4 thru CIP-009-4 xYes 1st (Thru

11310)Yes Recirc Thru

123010) - passed Yes (123010) Yes (12411) Yes (21011) Pending Regulatory Approval

21 Project 2008-14 ― Cyber Security Violation Severity Levels No CIP family of standardsYes 2nd (Thru

042009)Yes 1st (Thru


71609) Yes (71609) Date Date Pending Regulatory Approval

22 Project 2008-15 ― Interpretation of CIP-006-1a By US Army Corps of Engineers No CIP-006-1a R4 x xYes (Recirc Thru


23 Project 2008-18 ― Interpretation of TOP-005-1 and IRO-005-1 by Manitoba Hydro No TOP-005-1 R3 and IRO-005-1 R12 x xYes (Recirc Thru

42709) Yes (42709) Yes (11509) Yes (112409) NOPR issued 121610 - Comments are due 22711 Pending Regulatory Approval

24 Project 2009-09 ― Interpretation of CIP-001-1 by Covanta No CIP-001-1 R2 x xYes (Recirc Thru


25Project 2009-10 ― Interpretation of PRC-005-1 R1 by Compliance Monitoring Processes Working Group (CMPWG) No PRC-005-1 R1 x x

Yes (Recirc Thru 8609) Yes (8609) Yes (11509) Yes (111709) NOPR issued 121610 - Comments are due 22511 Pending Regulatory Approval

26Project 2009-11 ― Interpretation of IRO-010-1 R12 and R3 by WECC Reliability Coordination Subcommittee No IRO-010-1 R12 and R3 --gt IRO-010-1a x x

Yes (Recirc Thru 6509) Yes (6509) Yes (8509) Yes (123109) NOPR issued 111810 Comments were due 12411 Pending Regulatory Approval

27 Project 2009-12 ― Interpretation of CIP-005-1 by PacifiCorp No CIP-005-1 R13 x xYes (Recirc Thru


28 Project 2009-14 ― Interpretation of TPL-002-0 R1310 by PacifiCorp No TPL-002-0 R1310 x xYes (Recirc Thru

8609) Yes (8609) Yes (11509) Yes (111709)

bull FERC NOPR [Docket RM10-6-000] - FERC reject NERCrsquos proposed interpretation and instead proposes an alternative interpretation of the provision 31810 Pending Resolution of FERC NOPR

29 Project 2009-31 ― Interpretation of TOP-001-1 R8 by FMPP No TOP-001-1 R8 x xYes 1st (Intitial Thru 31610) Yes (31610) Yes (51210) Yes (71610)

bull On 21411 NERC responded to FERCrsquos request for databull On 12811 FERC requested additional information from NERC Pending Regulatory Approval

30 Project 2010-10 ― FAC Order 729 Yes FAC-013-2Yes 1st (Thru

42910)Yes 3rd (Thru

1811)Yes 3rd (Recirc Thru 12311) Yes (12311) Yes (12411) Yes (12811) Under Development

31 Urgent Action SAR for Revision No BAL-004-1 Yes 2nd (Thru

101807)Yes 2nd (Thru

101807)Yes 1st (Recirc Thru 12407) Yes (12407) Yes (32608) Yes (31109)

FERC NOPR [Docket RM09-13-000 (March 18 2010)] - Commission proposes to remand BAL-004-1 Pending Regulatory Approval

32 Project 2007-01 ― Underfrequency Load Shedding Yes EOP-003-1 and PRC-006-1Yes 3rd (Thru

32907)Yes 3rd (Thru

71610)Yes 6th (Recirc Thru 102810) Yes (102810) Yes (11410) Pending Regulatory Filing

33 Project 2007-04 ― Certifying System Operators No PER-003-1Yes 2nd (Thru

13108)Yes 1st (Thru

112009)Yes 3rd (Recirc Thru 121310) Yes (123110) Yes (21711) Pending Regulatory Filing

34Project 2008-09 ― Interpretation of EOP-001-0 R1 by Regional Entity Compliance Managers No EOP-001-0 R1 x x

Yes 4th (Recirc Thru 101410) Yes (101410) Yes (11410) Pending Regulatory Filing

NERC Reliability Standards Executive Tracking Summary

Page 2 of 3

Revised 3102011



Posted For Ballot

Industry Approved

NERC BOT Approved



35 Project 2009-06 ― Facility Ratings No FAC-008-2Yes 2nd (Thru

9909)Yes 2nd (Thru


36Project 2009-17 ― Interpretation of PRC-004-1 and PRC-005-1 R2 by Y-W Electric and Tri-State G amp T No PRC-004-1 and PRC-005-1 x x

Yes 3rd (Recirc Thru 12310) Yes (12310) Yes (21711) Pending Regulatory Filing

37 Project 2009-27 ― Interpretation of TOP-002-2a R10 by FMPP No TOP-002-2a R10 x xYes (Recirc Thru

101610) Yes (101610) Yes (11410) Pending Regulatory Filing

38 Project 2009-28 ― Interpretation of EOP-001-1 and EOP-001-2 R22 by FMPP No EOP-001-1 and EOP-001-2 x xYes (Recirc Thru


39Project 2010-09 ― Cyber Security Order 706B ― Nuclear Plant Implementation Plan No Various CIP Standards



Yes (Recirc Thru 7210) Yes (7210) Yes (8510) Pending Regulatory Filing

40 Project 2010-11 ― TPL Table 1 Order Yes TPL-002 Footnote bYes 1st (Thru

52610)Yes 3rd (Thru

1511)Yes 3rd (Recirc

Thru 2511) Yes (2511) Yes (21711)Ref FERC 31810 Order Setting Deadline for Compliance [Docket RM06-16-009] -- NERC to clarify Std TPL 002-0 Pending Regulatory Filing

41 Project 2010-13 ― Relay Loadability Order Yes PRC-023-2Yes 1st (Thru

91910)Yes 3rd (Thru

121610)

Yes 3rd (Recirculation Thru

3611) Yes (3611) Yes (31011)

On 31011 the NERC BOT approved PRC-023-2 and NERC Rules of Procedure Section 1700 - Challenges to Determinations Under Development

42 Project 2007-23 ― Violation Severity Levels No Six sets of VSLs for various standardsYes 2nd Supp (Thru 91610)

Yes 6th (Thru 21811)

Yes (Non-Binding Poll Thru 21811

NA - Non Binding Poll Only

Next StepsThe revised VSLs will be presented to the Board of Trustees for approval Under Development

43 Project 2009-20 ― Interpretation of BAL-003-0 R2 and R5 by Energy Mark Inc No BAL-003-01b x xYes (Recirc Thru

22610) Yes (22610) Under Development

44 Project 2006-02 ― Assess Transmission and Future Needs Yes TPL-001-2Yes 3rd (Thru

31607)Yes 5th (Informal

Thru 9210)Yes (Initial Thru

3110)Response to informal comments posted - Formal comments will be solicited later

On Hold - pending completion of Project 2010-11

45 Project 2006-06 ― Reliability Coordination YesCOM-001-2 COM-002-3 IRO-001-2 and IRO-014-2 (possibly IRO-003-2 - see comments)

Yes 3rd Supp (Thru 9310)

Yes 4th (Thru 3711)

Yes 1st (Intitial Thru 3711)

DT to address comments on Supplemental SAR SAR proposes to expand the scope of work under to address some directives from Order 693 that are associated with IRO-003-2 Under Development

46 Project 2007-07 ― Vegetation Management Yes FAC-003-2Yes 3rd (Thru

71707)Yes 5th (Thru

22811)Yes 4th (Initial Thru

71910) Under Development

47 Project 2007-17 ― Protection System Maintenance amp Testing Yes PRC-005-2Yes 1st (Thru

71007)

Yes 3rd (30 day formal Thru 121710)

Yes 6th (Successive Thru


48 Project 2008-10 ― Interpretation of CIP-006-1 R11 by Progress Energy No CIP-006 R11 x xYes 2nd (Initial Thru 101209)

Since at least one negative ballot included a comment the results are not final A second (or recirculation) ballot must be conducted Under Development

49Project 2009-19 ― Interpretation of BAL-002-0 R4 and R5 by NWPP Reserve Sharing Group No BAL-002-0 R4 and R5 x x

Yes (Intitial Thru 22610)

1) Pending recirculation ballot2) NERC Staff recommends that no further effort be spent on this interpretation instead allowing the BACSDT to use that energy to rewrite the standard Under Development

50 Project 2009-23 ― Interpretation of CIP-004-2 R3 by Army Corps of Engineers No CIP-004-2 x xYes 2nd (Intitial

Thru 4810) Pending recirculation ballot Under Development

51 Project 2009-24 ― Interpretation of EOP-005-1 R7 by FMPA No EOP-005-1 R7 x xYes 1st (Intitial Thru 11510) Balloting Deferred per Standards Committee Under Development

52 Project 2009-25 ― Interpretation of BAL-001-01 and BAL-002-0 by BPA No BAL-001-01a and BAL-002-0 x xYes 1st (Intitial Thru 11510) Pending recirculation ballot Under Development

53 Project 2009-26 ― Interpretation of CIP-004-1 by WECC No CIP-004-1 R2 R3 and R4 x xYes 1st (Intitial Thru 11910) Balloting Deferred per Standards Committee Under Development

54 Project 2009-29 ― Interpretation of TOP-002-2a R6 by FMPP No TOP-002-2a R6 x xYes 1st (Intitial Thru 22210) Pending recirculation ballot Under Development

55 Project 2009-30 ― Interpretation of PRC-001-1 R1 by WPSC No PRC-001-1 x xYes 1st (Intitial Thru 22610) Pending recirculation ballot Under Development

56 Project 2009-32 ― Interpretation of EOP-003-1 R3 and R5 by FMPP No EOP-003-1 R3 and R5 x xYes 2nd (Re-ballot


57 Project 2010-15 ― Urgent Action Revisions to CIP-005-3 No CIP-005-4Yes 1st (Thru

92710)Yes 2nd (Thru

121110)Yes 2nd (Initial Thru 121110)

Standard clasification downgraded from Urgent Action to Expedited Action Under Development

58 Project 2007-02 ― Operating Personnel Communications Protocols Yes COM-003-1 and COM-002-2Yes 2nd (Thru

5207)Yes 1st (Thru


59 Project 2007-03 ― Real-time Operations Yes TOP-001-2 TOP-002-3 and TOP-003-2Yes 2nd (Thru

90707)Yes 4th (Thru


60 Project 2007-06 ― System Protection Coordination No PRC-001-1Yes 1st (Thru

71007)Yes 1st (Thru


61 Project 2007-09 ― Generator Verification YesMOD-026-1 and PRC-024-1MOD-024-2


Yes 1st (Thru 4209)

Yes 1st (Thru 21810) Under Development

62 Project 2007-11 ― Disturbance Monitoring No PRC-002-1 and PRC-018-1Yes 1st (Thru

42007)Yes 1st (Thru


63 Project 2007-12 ― Frequency Response Yes BAL-003-1Yes 3rd (Thru

30907)Yes 1st

(Thru 3711) Posted for 30 day formal comment period Under Development

64 Project 2008-06 ― Cyber Security ― Order 706 (CIP-010-1 and CIP-011-1) Yes CIP-010-1 and CIP-011-1 xYes 1st (Informal

Thru 6310) Under Development

65 Project 2008-08 ― EOP VSL Revisions No EOP family of standardsYes 1st (Thru

51908)Yes 2nd (Thru

12309)

Subsequent to the last ballot (August 2009) of the VSLs for Projects 2007-23 and 2008-08 NERC staff reviewed the VSLs again for consistency with the FERC Guidelines The review identified some discrepancies and inconsistencies in the VSL assignments and some minor typographical errors NERC Staff along with members of the VSL drafting team proposed changes to VSLs and re-started process Under Development

66 Project 2008-12 ― Coordinate Interchange Standards No INT-004- INT-006-4 INT-009-2 INT-010-2 and INT-011-1Yes 1st (Thru

73108)Yes 1st (Thru


67 Project 2009-01 ― Disturbance and Sabotage Reporting Yes EOP-004-2Yes 1st (Thru

52109)Yes 2nd (Formal


Page 3 of 3

Revised 3102011



Posted For Ballot

Industry Approved

NERC BOT Approved



68 Project 2009-02 ― Real-time Reliability Monitoring and Analysis Capabilities Yes NewYes 2nd (Thru

21810)Yes 1st (Informal

Thru 4411) Concept White Paper posted for informal comment period Under Development

69 Project 2009-22 ― Interpretation of COM-002-2 R2 by the IRC No COM-002-2 x1st (30 day formal

thru 121810)

The team met Nov 17-18 2009 to draft a response Due to differences of opinion by the team they conducted a follow-up conference call on Dec 4 2009 NERC staff has disagreed with the interpretation and has asked that the team reconsider Under Development

70 Project 2010-07 ― Transmission Requirements at the Generator Interface NoVarious BAL CIP EOP FAC IRO MOD PER PRC TOP and VAR standards


Yes 1st(Thru 4411) Concept White Paper posted for informal comment period Project Deferred

71 Project 2010-16 ― Definition of System Operator No NERC Glossary Of TermsYes 1st (Thru

12310)Yes 1st (Thru


72 Project 2010-17 ― Definition of Bulk Electric System Yes NERC Glossary Of TermsYes 1st (Thru

12111)Yes 1st (Thru

12111)

73 Project 2010-INT-05 CIP-002-1 Requirement R3 for Duke Energy No CIP-002-1 R3 xYes 1st (Thru

10810)

74 Project 2008-01 ― Voltage and Reactive planning and control Yes VAR-001 and VAR-002Yes 2nd (Thru


75 Project 2008-02 ― Undervoltage Load Shedding No PRC-010-0 and PRC-022-1Yes 1st (Thru

021910)June 2010 SC meeting - Project deferred until Higher Priority projects are completed Project Deferred

76 Project 2009-03 ― Emergency Operations Yes EOP-001 EOP-002 EOP-003 and IRO-001Yes 1st (Thru


77 Project 2009-05 ― Resource Adequacy Assessments No NewYes 2nd (Thru


78 Project 2009-07 ― Reliability of Protection Systems No NewYes 1st (Thru

21809) Pending prioritization - may be postponed Under Development

79 Project 2010-08 ― Functional Model Glossary Revisions NoYes 1st (Thru


80 Project 2009-04 ― Phasor Measurement Units No Project has not started81 Project 2010-01 ― Support Personnel Training No Project has not started82 Project 2010-02 ― Connecting New Facilities to the Grid No Project has not started83 Project 2010-03 ― Modeling Data No Project has not started84 Project 2010-04 ― Demand Data No Project has not started85 Project 2010-05 ― Protection Systems No Project has not started86 Project 2010-06 ― Results-based Reliability Standards No Results-based Reliability Standards Transistion Plan Transistion Plan posted 72610

87 Project 2010-14 ― Balancing Authority Reliability-based Control No

As of July 28 2010 this project has merges Project 2007-18 - Reliability-based Controls and is now Project 2010-14 - Balancing Authority Reliability-based Control into a single project Under Development

88 Project 2010-INT-01 Interpretation of TOP-006-2 R12 and R3 for FMPP No TOP-006-2 R12 and R3 Balloting Deferred per Standards Committee On Hold89 Project 2010-INT-02 Interpretation of TOP-003-1 R2 for FMPP No TOP-003-1 R2 Balloting Deferred per Standards Committee On Hold90 Project 2010-INT-03 Interpretation of TOP-002-2a R2 R8 and R19 for FMPP No TOP-002-2a R2 R8 and R19 Balloting Deferred per Standards Committee On Hold91 Project 2010-INT-04 Interpretation of EOP-001-1 R24 for FMPP No EOP-001-1 R24 Balloting Deferred per Standards Committee On Hold

AcronymsSAR- Standards Authorization RequestRS- Reliability StandardDT- Drafting TeamSC - NERC Standards CommitteeTBD- To Be DeterminedBOT- NERC Board of Trustee

Page 1 of 1

Revised 2282011 Further details regarding the individual documents may be found at httpwwwnpccorgregStandardsUnderDevaspx

Line No Regional Standard ID Regional Reliability Standard TitleRSAR

PostedPosted for Comment

Posted For Ballot

Industry Approved

NPCC BOD Approved

NERC BOT Approved FERC Approved Comments Project Status

1 BPS-501-NPCC-01 Classification of Bulk Power System Elements (Withdrawn by RSC 80709)Yes 1st (Thru

2408) NA NA NA NA NA NA Withdrawn by RSC 80709 Withdrawn

2 PRC-002-NPCC-01 Disturbance MonitoringYes 1st (Thru

91008)Yes 3rd (Thru



3 PRC-006-NPCC-01 Automatic Underfrequency Load Shedding ProgramYes 1st (Thru

82508)Yes 2nd (Thru

7910)Yes 1st (Thru

12811)

- On 2611 NPCC RSC remanded standard back to the drafting team- Replaces Directory 12 Under frequency Load Shedding Program Requirements Under Development

4 BAL-002-NPCC-01 Regional Reserve SharingYes 1st (Thru


5 PRC-012-NPCC-01 Special Protection SystemsYes 1st (thru

81808) On Hold678910

AcronymsRSAR- Regional Standards Authorization RequestRRS- Regional Reliability StandardDT- Drafting TeamSC - NERC Standards CommitteeTBD- To Be DeterminedBOD- NPCC Board of DirectorsBOT- NERC Board of Trustee

NPCC Regional Reliability Standards Executive Tracking Summary

Page 1 of 2

Revised 1282011 Further details regarding the individual documents may be found at httpwwwnpccorgregStandardsopOtheraspx

Line No Type Document DescriptionEffective

Date Comments Status1 Criteria A-01 Criteria for Review and Approval of Documents2 Criteria A-03 Emergency Operation Criteria 3 Criteria A-05 Bulk Power System Protection Criteria A5 retired Directory 4 established4 Criteria A-07 Revise Critical Component Definition (Glossary of Tterms)5 Criteria A-08 NPCC Reliability Compliance and Enforcement Program 6 Criteria A-10 Classification of BPS Elements7 Criteria A-15 Disturbance Monitoring Equipment Criteria 8 Guideline B-01 NPCC Guide for the Application of Autoreclosing to the Bulk Power System9 Guideline B-12 Guidelines for On-Line Computer System Performance During Disturbances10 Guideline B-21 NPCC Guide for Analysis and Reporting of Protection System Misoperations To be retired - See C-4511 Guideline B-22 Guidelines for Implementation of the NPCC Compliance Program12 Guideline B-25 Guide to Time Suynchronization13 Guideline B-26 Guide for Application of Disturbance Recording Equipement 14 Guideline B-27 Regional Critical Asset Identification Methodology15 Guideline B-28 Guide for Generator Sequence of Events Monitoring16 Procedure C-00 Listing of NPCC Documents by Type

17 Procedure C-01NPCC Emergency Preparedness Conference Call Procedures - NPCC Security Conference Call Procedures

18 Procedure C-05 Monitoring Procedures for Emergency Operation Criteria19 Procedure C-07 Monitoring Procedures for the Guide for Rating Generating Capability

20 Procedure C-15 Procedures for Solar Magnetic Disturbances Which Affect Electric Power Systems21 Procedure C-17 Procedures for Monitoring and Reporting Critical Operating Tool Failures

22 Procedure C-21Monitoring Procedures for Conformance with Normal and Emergency Transfer Limits

23 Procedure C-25 Procedure to Collect Power System Event Data24 Procedure C-29 Procedures for System ModelingData Requirements and Facility Ratings

25 Procedure C-30Procedure for Task Force on System Protection Review of Disturbances and Protection Misoperations

26 Procedure C-32 Review Process for NPCC Reliability Compliance Enforcement Program27 Procedure C-33 Procedure for Analysis and Classification of Dynamic Control Systems28 Procedure C-36 Procedures for Communications During Emergencies29 Procedure C-39 Procedure to Collect Major Disturbance Event Data30 Procedure C-42 Procedure for Reporting and Reviewing System Disturbances31 Procedure C-43 NPCC Operational Review for the Integration of New facilities32 Procedure C-44 NPCC Regional Methodology and Procedures for Forecasting TTC and ATC

33 Procedure C-45

Procedure for Analysis and Reporting of Protection System Misoperations[CO-12 Seasonal Assessment Methodology (previously proposed but not issued - information included in the CO-12 Working Group scope instead )]

Procedure C-45 (re Protection System Misoperations) under development - will replace Guide B-21 (last updated 3111)

34 Criteria A-02 (retired) Basic Criteria for Design and Operation Of Interconnected Power Systems A2 retired Directory 1 established35 Criteria A-04 (retired) Maintenance Criteria for Bulk Power System Protection A4 retired 7112008 Directory 3 established36 Criteria A-06 (retired) Operating Reserve Criteria A6 retired 1222010 Directory 5 established37 Criteria A-11 (retired) Special Protection System Criteria Directory 7 established38 Criteria A-12 (retired) System Restoration Criteria A12 draft replaced by Directory 8 102108 Directory 8 established39 Criteria A-13 (retired) NPCC Inc Verification of Generator Gross and Net Real Power Capability A13 retired 1222200840 Criteria A-14 (retired) Verification of Generator Gross and Net Reactive Power Capability A14 retired 1222200841 Guideline B-02 (retired) Control Performance Guide B2 retired Content transferred to Directory 5 App 542 Guideline B-03 (retired) Guidelines for Inter-AREA Voltage Control B3 retired Replaced by Procedure C-4043 Guideline B-04 (retired) Guidelines for NPCC Area Transmission Reviews B4 retired Content transferred to Directory 1 AppB44 Guideline B-05 (retired) Bulk Power System Protection Guide B5 retired Content transferred to Directory 4 App A

NPCC Document Open Process Executive Tracking Summary

Page 2 of 2



Date Comments Status


45 Guideline B-06 (retired) Automatic Load Shedding Employing Underfrequency Threshold Relays B6 retired Replaced by Guideline B-0746 Guideline B-07 (retired) Automatic Underfrequency Load Shedding Program B7 retired Content transferred to Directory 4 App A47 Guideline B-08 (retired) Guidelines for Area Review of Resource Adequacy B8 retired Content transferred to Directory 1 AppD48 Guideline B-09 (retired) Guide for Rating Generating Capability B9 retired Replaced by Criteria A-13 Document on July 18 200749 Guideline B-10 (retired) Guidelines for Requesting Exclusions B10 retired Content transferred to Directory 1 App E50 Guideline B-11 (retired) Special Protection System Guideline B11 retired Replaced by Criteria A-1151 Guideline B-13 (retired) Guide for Reporting System Disturbances B13 retired Replaced by Procedure C-4252 Guideline B-24 (retired) Security Guidelines for Protection System IEDS B24 retired Content transferred to Directory 4 App A53 Procedure C-03 (retired) C3 retired Replaced by Procedure C-3654 Procedure C-04 (retired) Monitoring Procedure for Guides Inter-AREA Volt Control C4 retired Content transferred to Directory 1 App G55 Procedure C-08 (retired) Monitoring Procedures for Control Performance Guide C8 retired Content transferred to Directory 5 App 556 Procedure C-09 (retired) Monitoring Procedures for Operating Reserve Criteria C9 retired Content transferred to Directory 5 App 2 57 Procedure C-10 (discontinued) C10 discontinued58 Procedure C-11 (retired) Monitoring Procedures for Interconnected System Freq Response C11 retired Content transferred to Directory 5 App 159 Procedure C-12 (retired) Procedure Shared Activation Ten Minute Reserve C12 retired Content transferred to Directory 5 Sect 58 amp App 460 Procedure C-13 (retired) Operational Planning Coordination C13 retired Content transferred to Directory 1 App F61 Procedure C-14 (retired) C14 retired Procedure C-14 was incorporated in Procedure C-1362 Procedure C-16 (retired) Procedure for Review of New or Modified BPS SPS C16 retired Content transferred to Directory 7 AppB63 Procedure C-18 (retired) Procedure for Test amp Analysis Extreme Contingencies C18 retired Content transferred to Directory 1 AppC64 Procedure C-20 (retired) Procedures During Abnormal Operating Conditions C20 retired Content transferred to Directory 5 App 365 Procedure C-22 (retired) Procedure for Reporting amp Review Proposed BPS Protection Systems C22 retired Content transferred to Directory 4 App A66 Procedure C-35 (retired) NPCC Inter-Area Power System Restoration Procedure C35 retired Incorporated within Directory 8 System Restoration67 Procedure C-37 (retired) Operating Procedures for ACE Diversity Interchange C37 retired Content transferred to Directory 5 Sect51168 Procedure C-38 (retired) Procedure for Operating Reserve Assistance Content will be transferred to new Directory 5 Reserve

69 Procedure C-40 (retired) Procedures for Inter-AREA Voltage Control C40 retiredContent transferred to Directory 1 App G amp Directory 2 App B

Acronyms

Page 1 of 1


Line No DocumentDeveloped

From Description Version Date PhaseTask Force

ReviewPosted Open

ProcessRCC

Approval

Full Membership

Ballot Comments Status

1 Directory 1 Criteria A-2 Design and Operation of the Bulk Power System 12109 (V0)Yes 1st (Thru

22811) TFCO comments due 22811 Revision Under Development2 Directory 2 Criteria A-3 Emergency Operations 1611 (V3) V3 - Errata3 Directory 3 Criteria A-4 Maintenance Criteria for Bulk Power System Protection 6309 (V1)4 Directory 4 Criteria A-5 Bulk Power System Protection Criteria 12109 (V0)

5 Directory 5 Criteria A-6 Reserve 12210 (V0)Yes 1st (Thru

xxxx)Revision sent to TFCO for review on 11111 Revision Under Development

6 Directory 67 Directory 7 Criteria A-11 Special Protection Systems 122707 (V0)8 Directory 8 Criteria A-12 System Restoration 102210 (V1)9 Directory 9 Criteria A-13 Verification of Generator Gross and Net Real Power Capability 7709 (V1)

10 Directory 10 Criteria A-14 Verification of Generator Gross and Net Reactive Power Capability 7709 (V1)11 Directory 11

12 Directory 12 Under frequency Load Shedding Program Requirements 1611 (V2) V2 - ErrataWill be replaced by Regional Standard PRC-006-NPCC-01

13 NEW Regional Reserve Sharing

RCC has directed TFCO to develop solutions to regional reserve Sharing issues contained in a new draft Directory on Regional reserve Sharing

AcronymsMC - Members CommitteeRCC - Reliability Coordinating Committee

NPCC Directory Executive Tracking Summary

UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION

SUNSHINE ACT MEETING NOTICE

February 10 2011

The following notice of meeting is published pursuant to section 3(a) of the government in the Sunshine Act (Pub L No 94-409) 5 USC 552b

AGENCY HOLDING MEETING FEDERAL ENERGY REGULATORY COMMISSION DATE AND TIME February 17 2011 1000 AM PLACE Room 2C 888 First Street NE Washington DC 20426 STATUS OPEN MATTERS TO BE CONSIDERED Agenda

NOTE - Items listed on the agenda may be deleted without further notice

CONTACT PERSON FOR Kimberly D Bose MORE INFORMATION Secretary Telephone (202) 502-8400 For a recorded message listing items

struck from or added to the meeting call (202) 502-8627

This is a list of matters to be considered by the Commission It does not include a listing of all documents relevant to the items on the agenda All public documents however may be viewed on line at the Commissionrsquos website at httpwwwfercgov using the eLibrary link or may be examined in the Commissionrsquos Public Reference Room

967TH - MEETING

REGULAR MEETING

February 17 2011

1000 AM Item No Docket No Company

ADMINISTRATIVE A-1

AD02-1-000 Agency Business Matters

A-2

AD02-7-000

Customer Matters Reliability Security and Market Operations

ELECTRIC

E-1 ER03-563-066 Devon Power LLC

E-2 EL10-71-000 Puget Sound Energy Inc

E-3 RM11-9-000

Locational Exchanges of Wholesale Electric Power

E-4 RM11-7-000 AD10-11-000

Frequency Regulation Compensation in the Organized Wholesale Power Markets

E-5 RM10-17-000 Demand Response Compensation in Organized Wholesale Energy Markets

E-6 RM10-13-001 Credit Reforms in Organized Wholesale Electric Markets

E-7 RM08-13-001 Transmission Relay Loadability Reliability Standard

E-8 RM08-19-004 Mandatory Reliability Standards for the Calculation of Available Transfer Capability Capacity Benefit Margins Transmission Reliability Margins Total Transfer Capability and Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System

E-9 ER11-2411-000 ER11-2572-000

Southern California Edison Company California Independent System Operator Corporation

E-10 ER11-2455-000 ER11-2451-000


E-11 ER05-1056-005 Chehalis Power Generating LP

E-12 ER10-2869-000 Midwest Independent Transmission System Operator Inc

E-13 ER11-2427-000 ISO New England Inc

E-14 EL10-62-000 Alta Wind I LLC Alta Wind II LLC Alta Wind III LLC Alta Wind IV LLC Alta Wind V LLC Alta Wind VI LLC Alta Wind VII LLC Alta Wind VIII LLC Alta Windpower Development LLC TGP Development Company LLC

GAS

G-1 RP08-306-000 Portland Natural Gas Transmission System

G-2 IS08-390-002 SFPP LP

HYDRO

H-1 RM11-6-000 Annual Charges for Use of Government Lands

H-2 P-2210-209 Appalachian Power Company


H-4 P-12532-003 P-13317-001 P-13689-001

Pine Creek Mine LLC Bishop Paiute Tribe KC LLC

CERTIFICATES

C-1 CP10-485-000

Tennessee Gas Pipeline Company

Kimberly D Bose Secretary

A free webcast of this event is available through wwwfercgov Anyone with Internet access who desires to view this event can do so by navigating to wwwfercgovrsquos Calendar of Events and locating this event in the Calendar The event will contain a link to its webcast The Capitol Connection provides technical support for the free webcasts It also offers access to this event via television in the DC area and via phone bridge for a fee If you have any questions visit wwwCapitolConnectionorg or contact Danelle Springer or David Reininger at 703-993-3100 Immediately following the conclusion of the Commission Meeting a press briefing will be held in the Commission Meeting Room Members of the public may view this briefing in the designated overflow room This statement is intended to notify the public that the press briefings that follow Commission meetings may now be viewed remotely at Commission headquarters but will not be telecast through the Capitol Connection service

From Philip A FedoraTo grpStaffCc Kenneth Lotterhos pheidrichfrcccomSubject March 17 FERC Open Meeting AgendaDate Thursday March 10 2011 75308 PMAttachments 20110310163753-CA03-17-011pdfImportance High

Of Note

E-4 RM09-18-001 Revision to ElectricReliabilityOrganization Definitionof Bulk Electric System

E-5 RM11-14-000 Analysis of HorizontalMarket Power under theFederal Power Act

E-6 RM10-16-000 System RestorationReliability Standards

E-7 RM10-10-000 Planning ResourceAdequacy AssessmentReliability Standard

E-8 RM10-15-000 Mandatory ReliabilityStandards forInterconnectionReliability OperatingLimits



March 10 2011


AGENCY HOLDING MEETING FEDERAL ENERGY REGULATORY COMMISSION DATE AND TIME March 17 2011 1000 AM PLACE Room 2C 888 First Street NE Washington DC 20426 STATUS OPEN MATTERS TO BE CONSIDERED Agenda





968TH - MEETING

REGULAR MEETING

March 17 2011


ADMINISTRATIVE A-1


A-2

AD02-7-000


ELECTRIC E-1 ER03-563-066

Devon Power LLC

E-2 OMITTED

E-3 NP10-18-000 North American Electric Reliability Corporation

E-4 RM09-18-001 Revision to Electric Reliability Organization Definition of Bulk Electric System

E-5 RM11-14-000

Analysis of Horizontal Market Power under the Federal Power Act

E-6 RM10-16-000

System Restoration Reliability Standards

E-7 RM10-10-000 Planning Resource Adequacy Assessment Reliability Standard

E-8 RM10-15-000 Mandatory Reliability Standards for Interconnection Reliability Operating Limits

E-9 RM09-19-000 Western Electric Coordinating Council Qualified Transfer Path Unscheduled Flow Relief Regional Reliability Standard

E-10 RR09-6-003 North American Electric Reliability Corporation

E-11 OMITTED

E-12 ER11-2256-000

California Independent System Operator Corporation

E-13 EL08-47-006 PJM Interconnection LLC

E-14

EL11-12-000 Idaho Wind Partners 1 LLC

E-15 EL10-1-001 Southern California Edison Company

E-16 EL10-84-002 CAlifornians for Renewable Energy Inc v Pacific Gas and Electric Company Southern California Edison Company San Diego Gas amp Electric Company and the California Public Utilities Commission

GAS G-1 OMITTED

G-2 RP11-1495-002 Ozark Gas Transmission LLC

G-3 RP10-315-002

Columbia Gulf Transmission Company

G-4 OR07-7-000 Tesoro Refining and Marketing Company v Calnev Pipe Line LLC

OR07-18-000 America West Airlines Inc and US Airways Inc Chevron Products Company Continental Airlines Inc Southwest Airlines Co and Valero Marketing and Supply Company v Calnev Pipe Line LLC

OR07-19-000 ConocoPhillips Co v Calnev Pipe Line LLC OR07-22-000 BP West Coast Products LLC v Calnev Pipe

Line LLC OR09-15-000 Tesoro Refining and Marketing Company v Calnev

Pipe Line LLC OR09-20-000 BP West Coast Products LLC v Calnev Pipe

Line LLC

HYDRO

H-1 P-2539-061 Erie Boulevard Hydropower LP

H-2 P-2195-025 Portland General Electric Company

H-3 P-1390-063 Southern California Edison Company

CERTIFICATES C-1 OMITTED

C-2 CP10-492-000 Columbia Gas Transmission LLC

C-3 OMITTED

C-4 CP10-22-000

Magnum Gas Storage LLC Magnum Solutions LLC

C-5 CP10-486-000 Colorado Interstate Gas Company

Kimberly D Bose Secretary A free webcast of this event is available through wwwfercgov Anyone with Internet access who desires to view this event can do so by navigating to wwwfercgovrsquos Calendar of Events and locating this event in the Calendar The event will contain a link to its webcast The Capitol Connection provides technical support for the free webcasts It also offers access to this event via television in the DC area and via phone bridge for a fee If you have any questions visit wwwCapitolConnectionorg or contact Danelle Springer or David Reininger at 703-993-3100 Immediately following the conclusion of the Commission Meeting a press briefing will be held in the Commission Meeting Room Members of the public may view this briefing in the designated overflow room This statement is intended to notify the public that the press briefings that follow Commission meetings may now be viewed remotely at Commission headquarters but will not be telecast through the Capitol Connection service



March 10 2011







968TH - MEETING

REGULAR MEETING

March 17 2011


ADMINISTRATIVE A-1


A-2

AD02-7-000



Devon Power LLC

E-2 OMITTED



E-5 RM11-14-000


E-6 RM10-16-000






E-11 OMITTED

E-12 ER11-2256-000



E-14




GAS G-1 OMITTED


G-3 RP10-315-002







Line LLC

HYDRO






C-3 OMITTED

C-4 CP10-22-000




From Philip A FedoraTo grpStaffSubject FW NERCs Draft Response to FERCs Notice of Proposed Rulemaking (NOPR) The Integration of Variable Energy ResourcesDate Friday February 25 2011 50342 PMAttachments NERC_draft_VER_NOPR_comments_02-25-11docxImportance High

Nothing like giving adequate review time hellip

By the way Monday is February 28th hellip If you have any comments please provide to me by then Thanks Phil

From Mark Lauby [mailtoMarkLaubynercnet] Sent Friday February 25 2011 446 PMSubject NERCs Draft Response to FERCs Notice of Proposed Rulemaking (NOPR) The Integration of Variable Energy Resources

DraftNERCrsquos Comments Addressing FERCrsquos Notice of Proposed Rulemaking (NOPR) Dear Planning and Operating Committee Members On December 6 2010 NERC requested comments from the Operating and Planning Committee members (see below) on its directionalresponse to FERCrsquos Notice of Proposed Rulemaking (NOPR) titled Notice of Proposed Rulemaking (NOPR) Integration of Variable EnergyResources With input from both committees as well as the Integration of Variable Generation Task Force (IVGTF) leadership team andobservers NERC has developed its final draft comments (enclosed) which must filed on March 2 2011 Please submit your incremental comments to assessmentsnercnet by noon EST on Monday March 1 2011

Chrissy VegsoNorth American Electric Reliability Corporation

116-390 Village BlvdPrinceton NJ 08540

6094528060 | wwwnerccomchrissyvegsonercnet

From Chrissy Vegso Sent Monday December 06 2010 1007 AMTo Chrissy VegsoSubject DRAFT POSTED NERCs Directional Topics Addressing NERCs Response to FERCs Notice of Proposed Rulemaking (NOPR)

Draft PostedNERCrsquos Directional Topics Addressing NERCrsquos Response to FERCrsquos Notice ofProposed Rulemaking (NOPR) Dear Planning and Operating Committee Members The United States Federal Energy Regulatory Commission (FERC) recently released their Notice of Proposed Rulemaking (NOPR)

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

INTEGRATION OF VARIABLE)Docket No RM10-11-000

ENERGY RESOURCES)

COMMENTS OF THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION IN RESPONSE TO THE FEDERAL ENERGY REGULATORY COMMISSIONrsquoS NOVEMBER 18 2010 NOTICE OF PROPOSED RULEMAKING ON THE INTEGRATION OF VARIABLE ENERGY RESOURCES

March 2 2011

TABLE OF CONTENTS

IINTRODUCTION 1

IINOTICES AND COMMUNICATIONS 2

III BACKGROUND 2
IV DISCUSSION 3

a Inconsistency with Reliability Standards

b NERC Definition of Variable Energy Resource

c Reliability Impacts from Use of Existing or New Ancillary Services to Address Extreme Ramp Events

VCONCLUSION

I INTRODUCTION

The North American Electric Reliability Corporation (ldquoNERCrdquo) is pleased to provide these comments in response to the Federal Energy Regulatory Commissionrsquos (ldquoFERCrdquo or the ldquoCommissionrdquo) November 18 2010 Notice of Proposed Rulemaking (ldquoNOPRrdquo) on the Integration of Variable Energy Resources (ldquoVERsrdquo)[footnoteRef1] In the NOPR FERC proposes to ldquoreform the pro forma Open Access Transmission Tariff to remove unduly discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional servicesrdquo[footnoteRef2] [1 Integration of Variable Energy Resources 133 FERC para61149 (November 18 2010)(ldquoNOPRrdquo)] [2 NOPR at p 1]

NERCrsquos mission as the FERC-designated Electric Reliability Organization (ldquoEROrdquo)[footnoteRef3] is to ensure the reliability of the bulk power system in North America by in part developing and enforcing mandatory Reliability Standards NERCrsquos reliability mandate under section 215 of the Federal Power Act does not include authority to monitor and enforce market-based issues[footnoteRef4] Accordingly NERCrsquos comments herein focus on three separate areas related to the impact of the Integration of VERs on Reliability [3 See North American Electric Reliability Corporation ldquoOrder Certifying North American Electric Reliability Corporation as the Electric Reliability Organization and Ordering Compliance Filingrdquo 116 FERC para 61062 (July 20 2006)] [4 See Mandatory Reliability Standards for the Calculation of Available Transfer Capability Capacity Benefit Margins Transmission Reliability Margins Total Transfer Capability and Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System Order No 729 129 FERC para 61155 at P 109 (2009)]

II NOTICES AND COMMUNICATIONS

Notices and communications with respect to this filing may be addressed to the following

III BACKGROUND

On January 21 2010 FERC issued a Notice of Inquiry (ldquoNOIrdquo) on the Integration of Variable Energy Resources[footnoteRef5] In the NOI FERC sought comment on the extent to which barriers may exist that impede the reliable and efficient integration of VERs into the electric grid and whether reforms are needed to eliminate those barriers A 60-day comment period was set for interested parties to provide input NERC submitted comments in response to the NOI on April 12 2010[footnoteRef6] NERCrsquos comments provided responses that focused on the reliability impacts of integrating VERs into the grid and NERCrsquos ongoing efforts to address reliability considerations On November 18 2010 FERC issued its NOPR regarding the Integration of VERs in which it proposed to reform the pro forma Open Access Transmission Tariff to remove unduly discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional services[footnoteRef7] By this filing NERC provides comments in response to the NOPR [5 Integration of Variable Energy Resources 130 FERC para 61053 (January 21 2010) (ldquoNOIrdquo)] [6 See Comments Of The North American Electric Reliability Corporation In Response To The Federal Energy Regulatory Commissionrsquos January 21 2010 Notice Of Inquiry On The Integration Of Variable Energy Resources Docket No RM10-11-000 (April 12 2010)] [7 ldquoIntegration of Variable Energy Resourcesrdquo 133 FERC para 61149 (Nov 18 2010) (ldquoNOPRrdquo)]

IV DISCUSSION

In formulating its response to the NOPR NERC sought input from industry stakeholders the NERC Operating Committee NERC Planning Committee and the Integration of Variable Resources Task Force (ldquoIVGTFrdquo) To this end NERC posted to its website a letter addressed to its Planning and Operating Committees titled NERCrsquos Directional Topics Addressing NERCrsquos Response to FERCrsquos Notice of Proposed Rulemaking on Integration of Variable Energy Resources[footnoteRef8] In this posting NERC provided reliability considerations and sought input from the committee members on the three separate areas relating to the integration of VERs discussed below [8 httpwwwnerccomfilezpchtml ]

a Inconsistency with NERC Reliability Standards

In the NOPR the Commission proposed ldquoto amend sections 138 and 146 of the pro forma OATT to provide transmission customers the option to schedule transmission service on an intra-hour basis at intervals of 15 minutesrdquo[footnoteRef9] Noting that the proposed 15-minute interval was ldquoconsistent with the ideal time increments ( ie 5 to 15 minutes) recommended by NERCrdquo the Commission requested comment on whether there was any inconsistency among relevant NERC Reliability Standards and the proposed intra-hour scheduling tariff reform [9 NOPR at P 37]

In response to the Commissionrsquos request for comment NERC worked with industry stakeholders to perform a preliminary review of its Reliability Standards NERC has not identified any insurmountable hurdles that would prevent the industry from providing intra-hour scheduling flexibility NERC notes that certain entities currently offer various forms of scheduling on a 15-minutes basis and to date NERC is not aware of this causing any conflicts with NERCrsquos Reliability Standards
Yet NERC acknowledges that making a 15-minute scheduling interval more routine including (critically) for inter-Balancing Area (BA) transactions would likely require review and refinements to several existing Reliability Standards[footnoteRef10] In particular there would likely be a need for changes to NERCrsquos Interchange Scheduling and Maintenance Coordination (INT) Reliability Standards which were largely written based on the assumption that many schedules will be on an hourly basis To the extent that this assumption has resulted in wording that is consistent with an hourly regime interpretations or modifications to the INT Reliability Standards would likely be required While it is expected that only minor wording changes to affected standards may be necessary adopting interconnection-wide intra-hour scheduling could have a substantial impact on practices and tools used by transmission operators to maintain reliable operations Time and attention to the details (regarding impacts and changes to Reliability Standards practices and tools) would be required but a transition to more widespread use of intra-hour scheduling flexibility is achievable in a reasonable time frame [10 See eg NERC Reliability Standards BAL-005 R121 (Automatic Generation Control) BAL-006 R1 (Inadvertent Interchange) EOP-008 (Plans for Loss of Control Center Functionality) INT-001 R11 (Interchange Information) INT-004-2 (Dynamic Interchange Transaction Modifications) INT-005-003 (Interchange Authority Distributes Arranged Interchange) INT-006-3 (Response to Interchange Authority) INT-008 R1 (Interchange Authority Distributes Status)]

However it should be noted that all creation and modification of Reliability Standards must be considered as part of the NERC Reliability Standards Committee prioritization process This prioritization process considers the regulatory reliability and logistical issues associated with projects to create or modify NERC standards and helps determine the manner in which industry resources and NERC staff are deployed to create or modify Reliability Standards Additionally such changes must be developed in accordance with the steps outlined in the NERC Standards Process Manual which ensures an open and inclusive process through adherence to the standards development principles of the American National Standards Institute

In the NOPR the Commission proposed to ldquoallow all transmission customers the option of submitting intra-hour schedules up to 15 minutes before the scheduling intervalrdquo[footnoteRef11] NERC notes that the INT Reliability Standards have been written so that nearly all schedules are received at least 20 minutes ahead of the block-schedule start This 20-minute period was set to provide the operator sufficient time to evaluate approve and implement the schedule request For example if an Eastern Interconnection schedule request is submitted at 0040 for a schedule that starts at 0100 then industry actions may include [11 NOPR at 41]

middot communication time will be required as the request is transmitted received and processed

middot the entities reviewing the request will require sufficient time to evaluate the request

middot communication time will be required to verify that all entities have agreed to implement the requested schedule and coordinate that agreement between all entities and

middot entities will need time to input the request into their scheduling systems

When combined the required time is at least 15 minutes (0055) to perform these tasks with the remaining time allowing for the initiation of the ramp which in the Eastern Interconnection is based on the standard ramp of 10 minutes that straddles across the block-schedule start ( eg begin ramping at 0055 and complete ramping at 0105) Changes that impact this timing will need to be accounted for in modifications to the associated INT Reliability Standards ( ie INT-005 and INT-008) and will result in significant changes in the way in which operators currently process such requests As a result of this fairly tight advance notice time frame for processing schedule changes any change to the existing 20-minute prior notice evaluation period for schedules should be undertaken with caution

The Commission also requested comments regarding any changes that might be necessary in hardware software or personnel As indicated above NERC is informed that transmission providers offering and executing on 15 minute scheduling would require changes (some substantial) to existing tools and processes used to perform scheduling and curtailment activities For example the Interchange Distribution Calculator a tool which is used in the Eastern Interconnection to manage congestion generally operates on an hourly basis as does the Western Interconnections WebSAS tool In addition wide-spread intra-hour scheduling may require system operators to adopt increasingly automated processes as significant aspects of existing processes ( ie check out) are often performed manually The need to account for shorter-term schedules combined with the potential increase in volume of transactions processed would in some instances require changes to both hardware and software NERC believes such analysis would need to be performed subsequent to the issuance of a Final Rule (so the requirements are known) but before implementation becomes mandatory

While NERC does not have personnel that would be directly impacted by the proposed change NERC believes that entities that review and implement schedule requests would likely see their personnel needs increase Such entities would also likely see increased demands on their software and hardware associated with processing schedule requests

b NERC Definition of Variable Energy Resource

In the NOPR FERC proposed to define a VER as ldquoenergy source that (1) is renewable (2) cannot be stored by the facility owner or operator and (3) has variability that is beyond the control of the facility owner or operatorrdquo[footnoteRef12] Noting that this definition is consistent with NERCrsquos characterization of variable generation the Commission sought comment on the proposed VER definition NERC supports the VER definition proposed by the Commission and believes it is sufficient [12 NOPR at P 64 (citing NERC Accommodating High Levels of Variable Generation at 13-14 (2009) available at httpwwwnerccomfilesIVGTF_Report_041609pdf)]

c Reliability Impacts from Use of Existing or New Ancillary Services to Address Extreme Ramp Events

In the NOPR the Commission requested comments ldquoon the extent to which some additional type of contingency reserve service (beyond the services provided under Schedule 5 and 6 of the pro forma OATT) would ensure that VERs are integrated into the interstate transmission system in a non-discriminatory manner while remaining consistent with NERC Reliability Standardsrdquo[footnoteRef13] [13 NOPR at P 100]

Large wind ramping events have characteristics that are both similar to and different than conventional generator contingency events They are similar in that the large events are large and infrequent They differ in that wind ramps are much slower than instantaneous contingency events and the extreme wind ramps may be possible to forecast Figure 1 below shows a large (1500 MW) wind ramp event that occurred in February 2007 in the Electric Reliability Council of Texas (ldquoERCOTrdquo) region While this event is large and can present a serious operational challenge it is a rare event occurring about once a year and it emerges slowly compared with a conventional generation contingency which happens essentially instantaneously

Figure 1 ERCOT 2242007 wind event

The use of contingency reserves is similar to what is used to address large infrequent wind ramps because contingency reserves are seldom deployed Typically contingency reserves are split between spinning and non-spinning For large ramps lasting several hours the ramp duration make it difficult to include wind ramps as actual contingencies Resource and Demand Balancing (BAL) Reliability Standard BAL-002 (Disturbance Control Performance) requires ACE to be restored 15 minutes following the disturbance (R4) and the contingency reserves to be restored within 105 minutes (90 minutes after the 15 minute disturbance recovery period ndash R6) Both of these requirements can be problematic for wind ramps since they can be longer than the disturbance recovery period as well as the reserve restoration period System operators typically restore reserves much faster (within approximately ten minutes following the disturbance recovery period) Therefore including two hour wind ramps as contingencies would also be problematic

A further issue with a large long ramp is the point at which the event can be identified For example during the ERCOT event in the Figure 1 above a full 20 minutes into the event it may not be clear to the operator whether the wind power will continue declining or whether the ramp is (nearly) over This highlights the importance of an accurate wind forecast so that wind generators can schedule a reasonable forecast of their expected output

Still it may be appropriate to use contingency reserves in response to a portion of a wind ramp Shared contingency reserves could be used to initiate the response allowing time for alternate supply (or load reduction) to be implemented The frequency of ramp events would need to be studied to determine which ramps are compatible with contingency reserve use The industry should consider developing rules governing reserve deployment and restoration similar to those that currently address conventional contingencies would also need to be developed

Some entities are considering rules that will allow contingency reserves to be deployed to help manage large infrequent wind ramping events NERC believes that the industry should consider how best to deal with this incremental risk Specifically NERC believes that further analysis of how wind ramps can be recovered using contingency reserves should be undertaken as well as consideration of how wind generation can minimize the impacts of wind ramps through improved forecasting and market tools products and requirements The predictability duration magnitude and ramp rate of an event are all important factors that are used in determining how reserves for these events should be held

If Balancing Authorities can predict an occurring event and to some degree know the duration magnitude and ramp rate of a future event they can use that information to ensure that the correct reserve is ready to be deployed This type of analysis could potentially be done with historic data that demonstrates the characteristics of the wind regime of the particular balancing area (as shown in the Figure 1)

With improved forecasting systems real-time forecast information should also be used to assist in determining what reserve requirements to hold for such events

V CONCLUSION

NERC is pleased to provide these comments in response to the Commissionrsquos NOPR and looks forward to working with the Commission to ensure the successful integration of VERs while maintaining the reliability of the bulk power system

Respectfully submitted

6

CERTIFICATE OF SERVICE

I hereby certify that I have served a copy of the foregoing document upon all parties listed on the official service list compiled by the Secretary in this proceeding

Dated at Washington DC this 2nd day of March 2011

s Willie L Phillips

Willie L Phillips

Attorney for North American Electric Reliability Corporation

image1png

Integration of Variable Energy Resources NERC has posted a draft letter to the Planning and Operating Committees identifying threeareas of FERCrsquos Notice to which it intends to provide comments (httpwwwnerccomfilezpchtml) In this letter NERC providesdirectional reliability considerations and seeks input from the Planning and Operating Committee members

In addition to the Operating and Planning Committees NERC plans to seek detailed input from the Integration of the Variable ResourcesTask Force (IVGTF) Before filing NERC staffrsquos draft comments will be sent for your final consideration Please submit your comments to assessmentsnercnet by Monday December 20 2010

Chrissy VegsoNorth American Electric Reliability Corporation

116-390 Village BlvdPrinceton NJ 08540

6094528060 | wwwnerccomchrissyvegsonercnet

---You are currently subscribed to pc_plus as pfedoranpccorgTo unsubscribe send a blank email to leave-1249359-159822efb8cca4334e86463d80bb177caa7b75listservnerccom

UNITED STATES OF AMERICA BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

INTEGRATION OF VARIABLE ) Docket No RM10-11-000 ENERGY RESOURCES )

COMMENTS OF THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION IN RESPONSE TO THE FEDERAL ENERGY REGULATORY

COMMISSIONrsquoS NOVEMBER 18 2010 NOTICE OF PROPOSED RULEMAKING ON THE INTEGRATION OF VARIABLE ENERGY RESOURCES

Gerald W Cauley President and Chief Executive Officer David N Cook Sr Vice President and General Counsel North American Electric Reliability

Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet

Holly A Hawkins Attorney Willie L Phillips Attorney North American Electric Reliability

Corporation 1120 G Street NW Suite 990 Washington DC 20005-3801 (202) 393-3998 (202) 393-3955 ndash facsimile hollyhawkinsnercnet williephillipsnercnet

March 2 2011

TABLE OF CONTENTS

I INTRODUCTION 1

II NOTICES AND COMMUNICATIONS 2

III BACKGROUND 2

IV DISCUSSION 3

a Inconsistency with Reliability Standards

b NERC Definition of Variable Energy Resource

c Reliability Impacts from Use of Existing or New Ancillary Services to Address Extreme Ramp Events

V CONCLUSION

1

I

The North American Electric Reliability Corporation (ldquoNERCrdquo) is pleased to provide

these comments in response to the Federal Energy Regulatory Commissionrsquos (ldquoFERCrdquo or the

ldquoCommissionrdquo) November 18 2010 Notice of Proposed Rulemaking (ldquoNOPRrdquo) on the

Integration of Variable Energy Resources (ldquoVERsrdquo)

INTRODUCTION

1 In the NOPR FERC proposes to ldquoreform

the pro forma Open Access Transmission Tariff to remove unduly discriminatory practices and

to ensure just and reasonable rates for Commission-jurisdictional servicesrdquo2

NERCrsquos mission as the FERC-designated Electric Reliability Organization (ldquoEROrdquo)

3 is

to ensure the reliability of the bulk power system in North America by in part developing and

enforcing mandatory Reliability Standards NERCrsquos reliability mandate under section 215 of the

Federal Power Act does not include authority to monitor and enforce market-based issues4

Accordingly NERCrsquos comments herein focus on three separate areas related to the impact of the

Integration of VERs on Reliability

1 Integration of Variable Energy Resources 133 FERC para61149 (November 18 2010)(ldquoNOPRrdquo) 2 NOPR at p 1 3 See North American Electric Reliability Corporation ldquoOrder Certifying North American Electric Reliability Corporation as the Electric Reliability Organization and Ordering Compliance Filingrdquo 116 FERC para 61062 (July 20 2006) 4 See Mandatory Reliability Standards for the Calculation of Available Transfer Capability Capacity Benefit Margins Transmission Reliability Margins Total Transfer Capability and Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System Order No 729 129 FERC para 61155 at P 109 (2009)

2

II

Notices and communications with respect to this filing may be addressed to the

following

NOTICES AND COMMUNICATIONS

Gerald W Cauley President and Chief Executive Officer David N Cook Sr Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet Persons to be included on FERCrsquos service list are indicated with an asterisk NERC requests waiver of FERCrsquos rules and regulations to permit the inclusion of more than two people on the service list



III BACKGROUND

On January 21 2010 FERC issued a Notice of Inquiry (ldquoNOIrdquo) on the Integration of

Variable Energy Resources5

5 Integration of Variable Energy Resources 130 FERC para 61053 (January 21 2010) (ldquoNOIrdquo)

In the NOI FERC sought comment on the extent to which barriers

may exist that impede the reliable and efficient integration of VERs into the electric grid and

whether reforms are needed to eliminate those barriers A 60-day comment period was set for

interested parties to provide input NERC submitted comments in response to the NOI on April

3

12 20106 NERCrsquos comments provided responses that focused on the reliability impacts of

integrating VERs into the grid and NERCrsquos ongoing efforts to address reliability considerations

On November 18 2010 FERC issued its NOPR regarding the Integration of VERs in which it

proposed to reform the pro forma Open Access Transmission Tariff to remove unduly

discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional

services7

By this filing NERC provides comments in response to the NOPR

IV

In formulating its response to the NOPR NERC sought input from industry stakeholders

the NERC Operating Committee NERC Planning Committee and the Integration of Variable

Resources Task Force (ldquoIVGTFrdquo) To this end NERC posted to its website a letter addressed to

its Planning and Operating Committees titled NERCrsquos Directional Topics Addressing NERCrsquos

Response to FERCrsquos Notice of Proposed Rulemaking on Integration of Variable Energy

Resources

DISCUSSION

8

a Inconsistency with NERC Reliability Standards

In this posting NERC provided reliability considerations and sought input from the

committee members on the three separate areas relating to the integration of VERs discussed

below

In the NOPR the Commission proposed ldquoto amend sections 138 and 146 of the pro

forma OATT to provide transmission customers the option to schedule transmission service on

6 See Comments Of The North American Electric Reliability Corporation In Response To The Federal Energy Regulatory Commissionrsquos January 21 2010 Notice Of Inquiry On The Integration Of Variable Energy Resources Docket No RM10-11-000 (April 12 2010) 7 ldquoIntegration of Variable Energy Resourcesrdquo 133 FERC para 61149 (Nov 18 2010) (ldquoNOPRrdquo) 8 httpwwwnerccomfilezpchtml

4

an intra-hour basis at intervals of 15 minutesrdquo9

In response to the Commissionrsquos request for comment NERC worked with industry

stakeholders to perform a preliminary review of its Reliability Standards NERC has not

identified any insurmountable hurdles that would prevent the industry from providing intra-hour

scheduling flexibility NERC notes that certain entities currently offer various forms of

scheduling on a 15-minutes basis and to date NERC is not aware of this causing any conflicts

with NERCrsquos Reliability Standards

Noting that the proposed 15-minute interval

was ldquoconsistent with the ideal time increments (ie 5 to 15 minutes) recommended by NERCrdquo

the Commission requested comment on whether there was any inconsistency among relevant

NERC Reliability Standards and the proposed intra-hour scheduling tariff reform

Yet NERC acknowledges that making a 15-minute scheduling interval more routine

including (critically) for inter-Balancing Area (BA) transactions would likely require review and

refinements to several existing Reliability Standards10

9 NOPR at P 37

In particular there would likely be a

need for changes to NERCrsquos Interchange Scheduling and Maintenance Coordination (INT)

Reliability Standards which were largely written based on the assumption that many schedules

will be on an hourly basis To the extent that this assumption has resulted in wording that is

consistent with an hourly regime interpretations or modifications to the INT Reliability

Standards would likely be required While it is expected that only minor wording changes to

affected standards may be necessary adopting interconnection-wide intra-hour scheduling could

have a substantial impact on practices and tools used by transmission operators to maintain

10 See eg NERC Reliability Standards BAL-005 R121 (Automatic Generation Control) BAL-006 R1 (Inadvertent Interchange) EOP-008 (Plans for Loss of Control Center Functionality) INT-001 R11 (Interchange Information) INT-004-2 (Dynamic Interchange Transaction Modifications) INT-005-003 (Interchange Authority Distributes Arranged Interchange) INT-006-3 (Response to Interchange Authority) INT-008 R1 (Interchange Authority Distributes Status)

5

reliable operations Time and attention to the details (regarding impacts and changes to

Reliability Standards practices and tools) would be required but a transition to more widespread

use of intra-hour scheduling flexibility is achievable in a reasonable time frame

However it should be noted that all creation and modification of Reliability Standards

must be considered as part of the NERC Reliability Standards Committee prioritization process

This prioritization process considers the regulatory reliability and logistical issues associated

with projects to create or modify NERC standards and helps determine the manner in which

industry resources and NERC staff are deployed to create or modify Reliability Standards

Additionally such changes must be developed in accordance with the steps outlined in the

NERC Standards Process Manual which ensures an open and inclusive process through

adherence to the standards development principles of the American National Standards Institute

In the NOPR the Commission proposed to ldquoallow all transmission customers the option

of submitting intra-hour schedules up to 15 minutes before the scheduling intervalrdquo11

bull communication time will be required as the request is transmitted received and

processed

NERC

notes that the INT Reliability Standards have been written so that nearly all schedules are

received at least 20 minutes ahead of the block-schedule start This 20-minute period was set to

provide the operator sufficient time to evaluate approve and implement the schedule request

For example if an Eastern Interconnection schedule request is submitted at 0040 for a schedule

that starts at 0100 then industry actions may include

bull the entities reviewing the request will require sufficient time to evaluate the

request

11 NOPR at 41

6

bull communication time will be required to verify that all entities have agreed to

implement the requested schedule and coordinate that agreement between all

entities and

bull entities will need time to input the request into their scheduling systems

When combined the required time is at least 15 minutes (0055) to perform these tasks with the

remaining time allowing for the initiation of the ramp which in the Eastern Interconnection is

based on the standard ramp of 10 minutes that straddles across the block-schedule start (eg

begin ramping at 0055 and complete ramping at 0105) Changes that impact this timing will

need to be accounted for in modifications to the associated INT Reliability Standards (ie INT-

005 and INT-008) and will result in significant changes in the way in which operators currently

process such requests As a result of this fairly tight advance notice time frame for processing

schedule changes any change to the existing 20-minute prior notice evaluation period for

schedules should be undertaken with caution

The Commission also requested comments regarding any changes that might be

necessary in hardware software or personnel As indicated above NERC is informed that

transmission providers offering and executing on 15 minute scheduling would require changes

(some substantial) to existing tools and processes used to perform scheduling and curtailment

activities For example the Interchange Distribution Calculator a tool which is used in the

Eastern Interconnection to manage congestion generally operates on an hourly basis as does the

Western Interconnections WebSAS tool In addition wide-spread intra-hour scheduling may

require system operators to adopt increasingly automated processes as significant aspects of

existing processes (ie check out) are often performed manually The need to account for

shorter-term schedules combined with the potential increase in volume of transactions

7

processed would in some instances require changes to both hardware and software NERC

believes such analysis would need to be performed subsequent to the issuance of a Final Rule (so

the requirements are known) but before implementation becomes mandatory

While NERC does not have personnel that would be directly impacted by the proposed

change NERC believes that entities that review and implement schedule requests would likely

see their personnel needs increase Such entities would also likely see increased demands on

their software and hardware associated with processing schedule requests


In the NOPR FERC proposed to define a VER as ldquoenergy source that (1) is renewable

(2) cannot be stored by the facility owner or operator and (3) has variability that is beyond the

control of the facility owner or operatorrdquo12


Noting that this definition is consistent with

NERCrsquos characterization of variable generation the Commission sought comment on the

proposed VER definition NERC supports the VER definition proposed by the Commission and

believes it is sufficient

In the NOPR the Commission requested comments ldquoon the extent to which some additional

type of contingency reserve service (beyond the services provided under Schedule 5 and 6 of the

12 NOPR at P 64 (citing NERC Accommodating High Levels of Variable Generation at 13-14 (2009) available at httpwwwnerccomfilesIVGTF_Report_041609pdf)

8

pro forma OATT) would ensure that VERs are integrated into the interstate transmission system

in a non-discriminatory manner while remaining consistent with NERC Reliability Standardsrdquo13

Large wind ramping events have characteristics that are both similar to and different than

conventional generator contingency events They are similar in that the large events are large and

infrequent They differ in that wind ramps are much slower than instantaneous contingency

events and the extreme wind ramps may be possible to forecast Figure 1 below shows a large

(1500 MW) wind ramp event that occurred in February 2007 in the Electric Reliability Council

of Texas (ldquoERCOTrdquo) region While this event is large and can present a serious operational

challenge it is a rare event occurring about once a year and it emerges slowly compared with a

conventional generation contingency which happens essentially instantaneously

Figure 1 ERCOT 2242007 wind event

The use of contingency reserves is similar to what is used to address large infrequent wind

ramps because contingency reserves are seldom deployed Typically contingency reserves are

split between spinning and non-spinning For large ramps lasting several hours the ramp

13 NOPR at P 100

9

duration make it difficult to include wind ramps as actual contingencies Resource and Demand

Balancing (BAL) Reliability Standard BAL-002 (Disturbance Control Performance) requires

ACE to be restored 15 minutes following the disturbance (R4) and the contingency reserves to be

restored within 105 minutes (90 minutes after the 15 minute disturbance recovery period ndash R6)

Both of these requirements can be problematic for wind ramps since they can be longer than the

disturbance recovery period as well as the reserve restoration period System operators typically

restore reserves much faster (within approximately ten minutes following the disturbance

recovery period) Therefore including two hour wind ramps as contingencies would also be

problematic

A further issue with a large long ramp is the point at which the event can be identified

For example during the ERCOT event in the Figure 1 above a full 20 minutes into the event it

may not be clear to the operator whether the wind power will continue declining or whether the

ramp is (nearly) over This highlights the importance of an accurate wind forecast so that wind

generators can schedule a reasonable forecast of their expected output

Still it may be appropriate to use contingency reserves in response to a portion of a wind

ramp Shared contingency reserves could be used to initiate the response allowing time for

alternate supply (or load reduction) to be implemented The frequency of ramp events would

need to be studied to determine which ramps are compatible with contingency reserve use The

industry should consider developing rules governing reserve deployment and restoration similar

to those that currently address conventional contingencies would also need to be developed

Some entities are considering rules that will allow contingency reserves to be deployed to

help manage large infrequent wind ramping events NERC believes that the industry should

consider how best to deal with this incremental risk Specifically NERC believes that further

10

analysis of how wind ramps can be recovered using contingency reserves should be undertaken

as well as consideration of how wind generation can minimize the impacts of wind ramps

through improved forecasting and market tools products and requirements The predictability

duration magnitude and ramp rate of an event are all important factors that are used in

determining how reserves for these events should be held

If Balancing Authorities can predict an occurring event and to some degree know the

duration magnitude and ramp rate of a future event they can use that information to ensure that

the correct reserve is ready to be deployed This type of analysis could potentially be done with

historic data that demonstrates the characteristics of the wind regime of the particular balancing

area (as shown in the Figure 1)

With improved forecasting systems real-time forecast information should also be used to

assist in determining what reserve requirements to hold for such events

V CONCLUSION

NERC is pleased to provide these comments in response to the Commissionrsquos NOPR and

looks forward to working with the Commission to ensure the successful integration of VERs

while maintaining the reliability of the bulk power system

Respectfully submitted

Gerald W Cauley President and Chief Executive Officer David N Cook Sr Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet

s Willie L Phillips Holly A Hawkins Attorney Willie L Phillips Attorney North American Electric Reliability

Corporation 1120 G Street NW Suite 990 Washington DC 20005-3801 (202) 393-3998

11

(202) 393-3955 ndash facsimile hollyhawkinsnercnet williephillipsnercnet

CERTIFICATE OF SERVICE

I hereby certify that I have served a copy of the foregoing document upon all parties

listed on the official service list compiled by the Secretary in this proceeding

Dated at Washington DC this 2nd day of March 2011

s Willie L Phillips Willie L Phillips


Critical Energy Infrastructure Information Has Been Redacted From This Public Version

February 28 2011

VIA ELECTRONIC FILING

Ms Kimberly D Bose Secretary Federal Energy Regulatory Commission 888 First Street NE Washington DC 20426

Re North American Electric Reliability Corporation

Docket No RM06-16-000 Dear Ms Bose

The North American Electric Reliability Corporation (ldquoNERCrdquo) hereby submits this

filing in compliance with Paragraph 629 of the Federal Energy Regulatory Commissionrsquos

(ldquoFERCrdquo) Order No 693 Order No 693 requires that NERC provide a quarterly informational

filing regarding the timeframe to restore power to the auxiliary power systems of US nuclear

power plants following a blackout as determined during simulations and drills of system

restoration plans This filing contains the referenced material pertaining to the fourth quarter of

2010

NERC also submits a request to terminate its obligation to file quarterly informational

filings as required by Paragraph 629 of Order No 693 on the basis that NERC has fulfilled the

intent of the directive With the implementation of the NUC-001-2 standard that was approved

by FERC on April 1 2010 more explicit requirements are now in place to address the off-site

power concerns expressed by the NRC Accordingly as explained in more detail herein the

20110228-5264 FERC PDF (Unofficial) 2282011 44800 PM


express purpose of this data request that is the subject of these quarterly filings has been

superseded and the Commissionrsquos directives have been addressed

NERCrsquos filing consists of the following

bull This transmittal letter

bull A table of contents for the entire filing

bull A narrative description summarizing the data collected

bull Official Data Request to Fulfill FERC Order No 693 Requirements Restoration of Nuclear Power Plant Off-site Power Sources (Exhibit A) and

bull Restoration of Nuclear Power Plant Off-site Power Sources Data 4th Quarter 2010 (Exhibit B)

Please contact the undersigned if you have any questions


Holly Hawkins s Holly Hawkins






MANDATORY RELIABILITY STANDARDS ) Docket No RM06-16-000 FOR THE BULK POWER SYSTEM )

FOURTH QUARTER 2010 COMPLIANCE FILING OF THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION

IN RESPONSE TO PARAGRAPH 629 OF ORDER No 693 AND REQUEST TO TERMINATE COMPLIANCE FILING OBLIGATION

Gerald W Cauley President and Chief Executive Officer David N Cook Senior Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet

Holly A Hawkins Assistant General Counsel for Standards and

Critical Infrastructure Protection North American Electric Reliability Corporation 1120 G Street NW Suite 990 Washington DC 20005-3801 (202) 393-3998 (202) 393-3955 ndash facsimile hollyhawkinsnercnet

February 28 2011



TABLE OF CONTENTS

I Introduction 1

II Notices and Communications 2

III Summary of Restoration of Nuclear Power Plant Off-site Power Sources Data 2

IV Request to Terminate Data Collection Exercise 9 V Conclusion 13

EXHIBIT A ndash Official Data Request to Fulfill FERC Order No 693 Requirements Restoration of Nuclear Power Plant Off-site Sources EXHIBIT B ndash Restoration of Nuclear Power Plant Off-site Power Sources Data 4th Quarter 2010



1


FEDERAL ENERGY REGULATORY COMMISSION MANDATORY RELIABILITY STANDARDS ) Docket No RM06-16-000 FOR THE BULK POWER SYSTEM )



I

In its March 16 2007 Order

INTRODUCTION

1

1 Mandatory Reliability Standards for the Bulk-Power System 118 FERC para 61218 FERC Stats amp Regs para 31242 (2007) (Order No 693) Order on rehrsquog Mandatory Reliability Standards for the Bulk-Power System 120 FERC para 61053 (Order No 693-A) (2007)

the Federal Energy Regulatory Commission

(ldquoFERCrdquo) directed the North American Reliability Corporation (ldquoNERCrdquo) to provide a

quarterly informational filing regarding the timeframe to restore power to the auxiliary

power systems of US nuclear power plants following a blackout as determined during

simulations and drills of system restoration plans This filing includes information for the

fourth quarter of 2010 This filing also includes an explanation regarding why the data

collection exercise directed by FERC in Order No 693 is no longer necessary with the

implementation of the NUC-001-2 standard and the proposed EOP-005-2 standard

Given that the goal of the directive has been fulfilled continuing this reporting diverts

precious stakeholder regional entity and ERO resources from other activities



2

II


following


Gerald W Cauley President and Chief Executive Officer David N Cook Senior Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet Persons to be included on the FERCrsquos service list are indicated with an asterisk

Holly A Hawkins Assistant General Counsel for Standards

and Critical Infrastructure Protection North American Electric Reliability Corporation 1120 G Street NW Suite 990 Washington DC 20005-3801 (202) 393-3998 (202) 393-3955 ndash facsimile hollyhawkinsnercnet

III

SUMMARY OF RESTORATION OF NUCLEAR POWER PLANT OFF-SITE POWER SOURCES DATA

Background

In response to comments offered by the US Nuclear Regulatory Commission

during the Notice of Proposed Rulemaking process FERC expressed in Order No 693

its concern regarding the role and priority that nuclear power plants should have in bulk

power system restoration plans FERC addressed the concern in the discussion of the

EOP-005-1 mdash System Restoration Plans Reliability Standard Specifically in Paragraph

629 of Order No 693 FERC directed NERC as follows



3

In addition the [FERC] directs the ERO to gather data pursuant to sect395(f) of the [FERCrsquos] regulations from simulations and drills of system restoration on the time it takes to restore power to the auxiliary power systems of nuclear power plants under its data gathering authority and report that information to [FERC] on a quarterly basis

EOP-005-1 Requirement R11 and sub-requirement R114 identify the expected

priority for restoring off-site power to nuclear stations They state

R11 Following a disturbance in which one or more areas of the Bulk Electric System become isolated or blacked out the affected Transmission Operators and Balancing Authorities shall begin immediately to return the Bulk Electric System to normal

R114 The affected Transmission Operators shall give high priority to

restoration of off-site power to nuclear stations

Importantly while the requirement provides the instruction to give high priority to

off-site power restoration it does not specify target timeframes

NERC in its role as the Electric Reliability Organization (ldquoEROrdquo) and in

accordance with 18 CFR sect 392(d) is required to provide information as necessary to

FERC in order to implement section 215 of the Federal Power Act As such users

owners and operators of the bulk power system are required to provide the ERO with

information in support of this same objective

To collect the data necessary to respond to the FERC directive for nuclear power

plant off-site power source data NERC issued a data request process that was at that

time drafted as a proposed rule of procedure This procedure required NERC to post a

proposed ERO data request for industry comment followed by NERC Board of Trustees

approval before issuing it as a formal data request2

2 FERC has since approved Section 1600 of the Rules of Procedure known as the Data Rule which establishes the process for issuing ERO data requests

NERC posted the ldquonuclear data

requestrdquo for a 30-day industry comment period that began on June 26 2007 NERC



4

reviewed the comments received and presented a final version of the data request that

was adopted by the NERC Board of Trustees at its August 2 2007 meeting

The data presented in Exhibit B to this filing contains critical energy

infrastructure information Specifically the information set forth in Exhibit B to the

instant filing includes critical energy infrastructure information as defined by FERC

Rules of Practice and Procedure (18 CFR Part 388) FERC Orders and NERC Rules of

Procedure The information pertains to proprietary or business design information

including design information related to vulnerabilities of critical energy infrastructure

information that is not publicly available Accordingly the information set forth in

Exhibit B has been redacted from the public filing In accordance with the FERC Rules

of Practice and Procedure 18 CFR sect 388112 a non-public version of the information

redacted from the public filing is being provided under separate cover NERC requests

that the confidential non-public information be provided special treatment in accordance

with the above regulation

The ERO data request for nuclear power plant off-site power source restoration

data as approved by the NERC Board of Trustees is found in Exhibit A Following

Board of Trustees approval NERC began to collect nuclear data from US Transmission

Operators during the fourth quarter 2007 and will continue to collect the data quarterly

until otherwise directed by FERC This filing represents data captured for the fourth

quarter of 2010

The specific data requested of the Transmission Operators requests the following

information

bull Reporting entity

bull Name of exercise drill or simulation



5

bull Date of exercise drill or simulation

bull Name of nuclear plant

bull Unit designation (each unit must be included separately)

bull Identifier of off-site power source

bull Time duration when off-site power sources are lost to the restoration of first off-site power source (For this request the loss of off-site power sources is the simulated physical interruption of power in support of EOP-005-1 requirements) and

bull Discussion of scenario assumptions or constraints impacting the restoration of the initial off-site power source to the nuclear power plant

In addition the following clarifying language was included in the data request to

guide the Transmission Operators when supplying the requested data

Simulations drills or exercises that are implemented for individualized operator training requirements are not included in this request Simulations drills and exercises conducted to support the requirements of EOP-005-1 are included in this request This request is not intended to require additional simulations or studies to those conducted to satisfy EOP-005-1 requirements

It is important to note that EOP-005 focuses on restoration plans and does not contain any

requirement for restoration plans specific to nuclear plants Accordingly the reporting

conducted under this data request so far will not result in a tabulation resulting in reports

for each US nuclear plant

Exhibit B presents the raw data collected through this period of observation As

noted above for the public version of this report Exhibit B has been redacted to remove

the actual raw data collected through the period of observation in accordance with the

data survey and in recognition that the information requested constitutes confidential

critical energy infrastructure information Specifically Exhibit B contains information

that if released could identify system weaknesses and pose a risk of attack on existing

infrastructure NERC respectfully requests that the critical energy infrastructure



6

information be protected consistent with national energy security objectives and in

accordance with the cited regulation

NERC has not analyzed this data to identify the impact of the reported off-site

power source restoration times relative to the ability of the US nuclear power plants to

remain in a mode that permits a timely return to service However NERC will utilize the

information contained herein to ensure applicable entities are supporting their reliability

standard obligations as defined in EOP-005-1 relative to the priority of off-site power

source restoration to nuclear power plants in plans for system restoration

Summary of Data

There are a total of 104 nuclear units in the US Of these 44 were included in

exercises drills or simulations in support of EOP-005-1 in the fourth quarter of 2010

Overall Transmission Operators conducted a total of 41 individual exercises drills or

simulations during this period that included the restoration of off-site power sources to

the 44 units with many events impacting more than one nuclear unit For example an

entity conducted one system restoration exercise on October 12 2010 that involved the

restoration of offsite power sources to a total of three nuclear units In the summary chart

that follows below each offsite power source restoration ldquoeventrdquo is reported separately

for purposes of data analysis In total one hundred twenty two (122) off-site power

source restoration ldquoeventsrdquo are included in the raw data presented in Exhibit B of this

filing



7

Of the one hundred twenty two (122) events there were ninety-four (94)3

NERC categorized the restoration of first off-site sources in two-hour windows

Over eighty-eight (88) percent (83 of 94) of the initial off-site power source restorations

occurred within the first six hours following the simulated blackout event with over

forty-eight (48) percent (46 of 94) occurring in two hours or less Twenty-three (23)

sources were simulated to be restored in the 2 to 4 hour window

potential initial off-site source restorations (some units have multiple off-site sources)

The remaining twenty-eight (28) events included in the data involved the restoration of a

subsequent off-site source beyond the first source restored Of the twenty-eight (28)

events one (1) subsequent source was simulated to be restored in less than 2 hours three

(3) sources in the 2 to 4 hour window thirteen (13) sources were simulated to be restored

in the 4 to 6 hour window three (3) sources were simulated to be restored in the 6 to 8

hour window eight (8) sources were simulated to be restored in the 8 to 10 hour window

Total Number Offsite Power Source Restoration Events Included in EOP-005-1 Exercises Drills or Simulations

94

Potential first off-site source restorations

46

Exercises Drills or Simulations in which the first off-site source was restored in 2 hours or less following the loss of

power

23

Exercises Drills or Simulations in which the first off-site source was restored 2-4 hours following the loss of power

14


0


0

3 Not all units provided data for off-site sources beyond the first source restored The data included represents only the units that provided the data and does not include the entire spectrum of off-site sources beyond the initial source for the rest of the units



8

Exercises Drills or Simulations in which the first off-site

source was restored 8-10 hours following the loss of power

1

Exercises Drills or Simulations in which the first off-site source was restored more than 10 hours following the loss of

power

10

Exercises Drills or Simulations that did not achieve the restoration of the first off-site power source to a nuclear

power plant or that did not report a time for source restoration

0



9

IV

REQUEST TO TERMINATE DATA COLLECTION EXERCISE

NERC has collected data in support of the FERC request for twelve quarters

Paragraph 625 of Order No 693 summarized the comments from the Nuclear Regulatory

Commission (ldquoNRCrdquo) in response to the then-proposed EOP-005-1 Reliability Standard

625 NRC suggests that this Reliability Standard include (1) a requirement to record the time it takes to restore power to the auxiliary power systems of nuclear power plants (2) a provision stating that the affected transmission operators shall give high priority to restoration of off-site power to nuclear power plants whether or not a nuclear power plant is being powered from the nuclear power plantrsquos onsite power supply and (3) a provision stating that restoration shall not violate nuclear power plant minimum voltage and frequency requirements

In response FERC noted in Paragraph 629 that

629 NRC raises several issues concerning the role and priority that nuclear power plants should have in system restorations The Commission shares these concerns and directs the ERO to consider the issues raised by NRC in future revisions of the Reliability Standard through the Reliability Standards development process In addition the Commission directs the ERO to gather data pursuant to sect 395(f) of the Commissionrsquos regulations from simulations and drills of system restoration on the time it takes to restore power to the auxiliary power systems of nuclear power plants under its data gathering authority and report that information to the Commission on a quarterly basis

Since the issuance of FERCrsquos Order No 693 in March 2007 NERC has

addressed the issues raised by the NRC in its development of the NUC-001-2 Reliability

Standardmdash Nuclear Plant Interface Coordination that was approved by FERC on April 1

2010 The NUC-001-2 standard requires a Nuclear Plant Generator Operator to

coordinate operations and planning with Transmission Entities providing services relating

to nuclear plant operating and off-site power delivery requirements NUC-001-2 also

requires Nuclear Plant Generator Operators and Transmission Entities to execute and



10

implement interface agreements setting forth expectations and procedures for

coordinating operations to meet the nuclear plant licensing requirements and system

operating limits affecting nuclear plant operations

The Commissionrsquos specific concerns in Paragraph 629 of Order No 693 are

addressed by the Requirements of the NUC-001-2 standard For example in Order No

693 the Commission directed NERC to gather data from simulations and drills of system

restoration on the time it takes to restore power to the auxiliary power systems of nuclear

power plants The currently-effective Requirement R922 of NUC-001-2 requires

Nuclear Plant Generator Operators to identify facilities components and configuration

restrictions that are essential for meeting the Nuclear Interface Plant Requirements

(ldquoNPIRsrdquo) Requirement R934 includes provisions to address mitigating actions needed

to avoid violating NPIRs and to address periods when responsible Transmission Entities

lose the ability to assess the capability of the electric system to meet the NPIRs (emphasis

added) These provisions also include the obligation to notify the Nuclear Plant

Generator Operator of this information within a specified time frame

Additionally Requirement R935 of NUC-001-2 includes provisions for

considering within the restoration process the requirements and urgency of a nuclear

plant that has lost all off-site and on-site AC power Requirement R4 provides that the

applicable Transmission Entities shall incorporate the NPIRs into their operating analyses

of the electric system operate the electric system to meet the NPIRs and inform the

Nuclear Plant Generator Operator when the ability to assess the operation of the electric

system affecting NPIRs is lost



11

The current data request that NERC issued in 2007 to begin collecting the data

required by these quarterly compliance filings was limited to those instances where drills

were conducted under EOP-005 Given the fact that a broader approach involving the

establishment of NPIRs under the NUC-001-2 standard is now in place specifically to

address the off-site power capability concerns of the NRC the Commissionrsquos concerns

on this issue that were raised in Order No 693 have been addressed

Similarly NERC filed EOP-005-2 mdash System Restoration from Blackstart

Resources for FERC approval on December 31 2009 In it the Transmission Operator

shall have a Reliability Coordinator-approved restoration plan that includes ldquo[a]

description of how all Agreements or mutually agreed upon procedures or protocols for

off-site power requirements of nuclear power plants including priority of restoration will

be fulfilled during System restorationrdquo

The Commission issued a Notice of Proposed Rulemaking on the System

Restoration Reliability Standards which includes NERCrsquos proposed EOP-005-2

Reliability Standard on November 18 2010 (lsquoNovember 18 NOPRrdquo)4 In the November

18 NOPR FERC proposed to approve the EOP-005-2 standard stating that the proposed

Reliability Standard effectively addresses the Commissionrsquos directive in Order No 693 to

develop timeframes for training and review of restoration plan requirements to simulate

contingencies and prepare operators for anticipated and unforeseen events5

On the basis that the more explicit requirements contained in the FERC-approved

NUC-001-2 standard and the proposed EOP-005-2 standard are now either in place or

NERC

responded to the Commissionrsquos November 18 NOPR on January 24 2011

4 System Restoration Reliability Standards Notice of Proposed Rulemaking 133 FERCpara61161 (November 18 2010) 5 Id at P 19



12

awaiting FERC approval NERC submits that the express purpose of conducting the data

request that is the subject of this filing has been superseded Considering this point and

the significant level of effort for Transmission Operators to collect and forward the

information to the Regional Entity the Regional Entityrsquos effort to accumulate and

assemble the data and NERCrsquos efforts to combine the information into the filings that

have been submitted NERC believes it is appropriate to redirect these resources to other

reliability activities with greater impact on the reliability of the bulk power system and

more efficient use of industry regional and ERO resources NERC therefore respectfully

requests that FERC terminate NERCrsquos obligation to collect and file the data called for

under this program



13

IV

NERC respectfully requests that FERC accept this informational filing for the

fourth quarter of 2010 in accordance with FERCrsquos directive that NERC provide

information regarding the time it takes to restore off-site power sources to nuclear power

plants following a blackout as determined by drills and simulations Additionally NERC

requests that FERC terminate the ongoing obligation to collect and file such data on the

basis that new standards approved by FERC or pending FERC approval contain more

explicit instructions regarding expectations of the Transmission Operators for restoring

off-site power sources to nuclear power plants following a service interruption

CONCLUSION



s Holly Hawkins






I hereby certify that I have served a copy of the foregoing document upon all

parties listed on the official service list compiled by the Secretary in this proceeding

Dated at Washington DC this 28th

day of November 2010

Holly A Hawkins s Holly A Hawkins




Exhibit A

Official Data Request to Fulfill FERC Order No 693 Requirements Restoration of

Nuclear Power Plant Off-site Power Sources



August 24 2007

TRANSMISSION OPERATOR CONTACT TITLE COMPANY ADDRESS CITY STATE ZIP CODE (TNR 12pt) Dear XXXXX

Official Data Request to Fulfill FERC Order No 693 Requirements Restoration of Nuclear Power Plant Off-site Power Sources

Pursuant to the authority granted by FERC Order 672 and as implemented in Title 18 Section 392 of the Code of Federal Regulations NERC as the appointed electric reliability organization issues this official data request as described in Attachment 1 The legal basis in the United States for this authority is explained in FERCrsquos Order 672 paragraph 114

114 The Commission agrees with commenters that to fulfill its obligations under this Final Rule the ERO or a Regional Entity will need access to certain data from users owners and operators of the Bulk-Power System Further the Commission will need access to such information as is necessary to fulfill its oversight and enforcement roles under the statute Section 392 of the regulations will include the following requirement

(d) Each user owner or operator of the Bulk-Power System within the United States (other than Alaska and Hawaii) shall provide the Commission the Electric Reliability Organization and the applicable Regional Entity such information as is necessary to implement section 215 of the Federal Power Act as determined by the Commission and set out in the Rules of the Electric Reliability Organization and each applicable Regional Entity The Electric Reliability Organization and each Regional Entity shall provide the Commission such information as is necessary to implement section 215 of the Federal Power Act

Within the United States failure to comply with an official data request would constitute a violation of FERC regulations Enforcement action is available to FERC to deal with

Gerry Adamski Vice President and

Director of Standards



violations of its regulations This is authority FERC could exercise not authority available to NERC NERCrsquos Compliance Monitoring and Enforcement Program including the ability to impose penalties and sanctions is limited to violations of reliability standards Please note the following additional pieces of information relative to this data request

bull An Excel spreadsheet (attached) to serve as a template for providing the requested information

bull Regional entities are requested to submit the requested information to sarcommnercnet

Thank you for your support of this effort Please contact me should you have any questions Sincerely

Enclosure cc James D Castle Chairman Operating Reliability Subcommittee

Regional Entity Management Group



Exhibit A Restoration of Nuclear Power Plant Offsite Power Source Data Request

Background In paragraph 629 of Order No 693 FERC directs NERC to provide an informational filing regarding the timeframe to restore auxiliary power to nuclear power plants following a blackout as determined during simulations and drills of system restoration plans

629 ldquoIn addition the Commission directs the ERO to gather data pursuant to sect 395(f) of the Commissionrsquos regulations from simulations and drills of system restoration on the time it takes to restore power to the auxiliary power systems of nuclear power plants under its data gathering authority and report that information to the Commission on a quarterly basisrdquo

Description of Data Requested This request is an ongoing request that begins in the fourth quarter of 2007 If an exercise drill or simulation includes the restoration of one or more offsite power sources to a nuclear power plant the following information is to be prepared and provided for each offsite power source in a format developed and provided by NERC

bull Reporting entity bull Name of exercise drill or simulation bull Date of exercise drill or simulation bull Name of nuclear plant bull Unit designation (each unit must be included separately) bull Identifier of offsite power source bull Time duration when offsite power sources are lost to the restoration of first

offsite power source (For this request the loss of offsite power sources is the simulated physical interruption of power in support of EOP-005-1 requirements)

bull Discussion of scenario assumptions or constraints impacting the restoration of the initial offsite power source to the nuclear power plant

Simulations drills or exercises that are implemented for individualized operator training requirements are not included in this request Simulations drills and exercises conducted to support the requirements of EOP-005-1 are included in this request This request is not intended to require additional simulations or studies to those conducted to satisfy EOP-005-1 requirements The individual data submissions should be submitted to the regional entity who will compile the data in a consolidated format The regional entity will then forward the complied data to NERCrsquos director of standards on a quarterly basis To comply with FERC directives NERC will make a quarterly filing with FERC that includes the compiled data



How the Data Will Be Used The data will be provided to FERC per its directive in Order 693 FERC agrees with issues raised by the Nuclear Regulatory Commission (NRC) concerning the role and priority nuclear power plants should have in system restorations and directs the collection of this data to aid in its review of this issue How the Data Will Be Collected and Validated The regional entities are requested to coordinate the collection and composite presentation of the requested data from its member participants Transmission operators responsive to this request are expected to validate the data to be correct prior to submittal Reporting Entities Each transmission operator in the United States who has a nuclear power plant tied to a transmission line that it controls and who is participating in an exercise drill or simulation in support of the EOP-005-1 standard will report Transmission operators that do not have a nuclear power plant tied to a transmission line it controls are exempt from this request Transmission operators outside the United States subject to EOP-005-1 are voluntarily encouraged to submit this information as well NERC will seek permission from these non-US entities for inclusion of its data in the information filed with FERC Due Date for the Information If a transmission operator subject to this data request conducts a drill simulation or exercise that includes restoration of the initial offsite power source to a nuclear power plant the transmission operator is to submit the requested information to its regional entity by the fifteenth of the month following the end of the previous three-month quarter The regional entity is to provide a quarterly report of all such submissions by April 30 July 31 October 31 and January 31 for the three-month period that concludes on these dates This data request begins in the fourth quarter of 2007 If no drill exercise or simulation meeting the criteria described above is conducted during a quarter no submission by the transmission operator and regional entity is required This data request does not direct transmission operators to conduct quarterly exercises drills or simulations to satisfy this data request It does require the data to be reported if such a simulation drill or exercise is conducted Restrictions on Disseminating Data (ConfidentialCEII) NERC will provide this data to FERC per its Order No 693 directives This information will be treated as critical energy infrastructure information when submitted to FERC Estimate on Burden Imposed to Collect Data There will be ongoing costs for the staff of responsible entities to respond and for regional entities to collect compile and report to NERC the requested data



Exhibit B

Restoration of Nuclear Power Plant Off-site Source Data 4th Quarter 2010


Document Content(s)

Final_NUC_filing_DraftQ42010_20110228(PUBLIC)PDF1-24


From Guy V ZitoTo grpStaffSubject FW AnswerResponse to a PleadingMotion submitted in FERC RM06-16-000 by North American Electric

Reliability Corporationet alDate Wednesday March 02 2011 95543 AM

NERC had filed a motion to cease developing and submitting quarterly reports for the timeframe torestore auxiliary power to Nuclear units The submission states that with the new NUC-001-2 theprevious directives in Order 693 have been addressed I will keep staff informed as FERC rules on this

Thanks

Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax________________________________________From FERC eSubscription [eSubscriptionfercgov]Sent Tuesday March 01 2011 740 AMSubject AnswerResponse to a PleadingMotion submitted in FERC RM06-16-000 by North AmericanElectric Reliability Corporationet al

On 2282011 the following Filing was submitted to the Federal Energy Regulatory Commission (FERC)Washington DC

Filer North American Electric Reliability Corporation North American Electric Reliability Corp (as Agent) North American Electric Reliability Corporation North American Electric Reliability Corp (as Agent)

Docket(s) RM06-16-000Filing Type AnswerResponse to a PleadingMotionDescription Fourth Quarter 2010 Compliance Filing of the North American Electric ReliabilityCorporation in Response to Paragraph 629 Of Order No 693 and Request to Terminate ComplianceFiling Obligation in Docket No RM06-16-000

To view the document for this Filing click herehttpelibraryFERCgovidmwsfile_listaspaccession_num=20110228-5264

To modify your subscriptions click here httpsferconlinefercgoveSubscriptionaspx

------------------------------------------------------------------------Please do not respond to this emailOnline help is available herehttpwwwfercgovefiling-helpaspor for phone support call 866-208-3676Comments and Suggestions can be sent to this email address mailtoFERCOnlineSupportFercgov

From Guy V ZitoTo rscSubject FW Commission OrderOpinion issued in FERC RM06-22-014Date Thursday March 10 2011 73744 PMImportance High

FYI

Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax________________________________________From Guy V ZitoSent Thursday March 10 2011 726 PMTo grpStaffSubject FW Commission OrderOpinion issued in FERC RM06-22-014

To All

FYI FERC dismisses the NERCs compliance filing regarding Implementation Plans and ldquoscope ofsystems determinationrdquo for Nuclear units The ldquoscope of systems determinationrdquo identifies whichsystems structures and components within the balance of plant at nuclear power facilities will besubject to NRCrsquos cyber security regulations and which will be subject to NERCrsquos CIP Standards This ispursuant to the MOU between the NRC and FERC NRCs cyber security rule covers the balance of plantof the Nuclear Units that was in question

Thank-you

Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax________________________________________From FERC eSubscription [eSubscriptionfercgov]Sent Thursday March 10 2011 606 PMSubject Commission OrderOpinion issued in FERC RM06-22-014

On 3102011 the Federal Energy Regulatory Commission (FERC) Washington DC issued thisdocument

Docket(s) RM06-22-014Filing Type Commission OrderOpinionDescription Order dismissing compliance filing re Mandatory Reliability Standards for CriticalInfrastructure Protection under RM06-22

To view the document for this Issuance click herehttpelibraryFERCgovidmwsfile_listaspaccession_num=20110310-3042



130 FERC para 61185 UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners Jon Wellinghoff Chairman Marc Spitzer Philip D Moeller and John R Norris Mandatory Reliability Standards for Critical Infrastructure Protection

Docket No RM06-22-011

ORDER ADDRESSING COMPLIANCE FILING AND APPROVING IMPLEMENTATION PLAN

(Issued March 18 2010)

1 On January 19 2010 the North American Electric Reliability Corporation (NERC) submitted a compliance filing in response to the Commissionrsquos December 17 2009 order1 addressing NERCrsquos plan for the implementation of eight Critical Infrastructure Protection Reliability Standards CIP-002-1 through CIP-009-1 (CIP Standards) by generator owners and operators of nuclear power plants located in the United States (Implementation Plan)

2 In this order we accept NERCrsquos compliance filing and approve the Implementation Plan for nuclear power plant generator ownersrsquo and operatorsrsquo compliance with Version 1 of the CIP Standards to become effective on the date of this order In addition the Commission directs NERC to make a compliance filing submitting implementation plans for the implementation of Versions 2 and 3 of the CIP Standards by owners and operators of US nuclear power plants on the same schedule established for Version 1 under the Implementation Plan

I Background

3 In Order No 706 the Commission approved Version 1 of the CIP Standards CIP-002-1 through CIP-009-12 The CIP Standards require certain users owners and

(continuedhellip)

1 Mandatory Reliability Standards for Critical Infrastructure Protection 129 FERC para 61224 (2009) (December 17 Order)

2 Mandatory Reliability Standards for Critical Infrastructure Protection Order No 706 122 FERC para 61040 at P 86-90 order on rehrsquog Order No 706-A 123 FERC

Docket No RM06-22-010 - 2 -

operators of the Bulk-Power System to comply with specific requirements to safeguard critical cyber assets The Commission also directed NERC to develop certain modifications to the CIP Standards3

4 Each Version 1 CIP Standard provides that facilities regulated by the US Nuclear Regulatory Commission (NRC) are exempt from complying with the CIP Standard4 On March 19 2009 the Commission issued Order No 706-B clarifying that because the NRC regulations do not extend to all equipment within a nuclear power plant the CIP Standards apply to the ldquobalance of plantrdquo equipment within a nuclear power plant located in the United States that is not regulated by the NRC5 In Order No 706-B the Commission directed NERC to engage in a stakeholder process to develop a more appropriate timeframe for nuclear power plantsrsquo full compliance with the CIP Standards and to submit a compliance filing that sets forth a proposed implementation plan for nuclear power plants to comply with the CIP Standards6

5 On May 22 2009 NERC filed revised CIP Standards Version 2 in compliance with Order No 706 By order issued September 30 2009 the Commission approved the Version 2 CIP Standards to become effective on April 1 20107 The Commission clarified that the September 30 Order does not alter its findings in Order No 706-B regarding the applicability of the CIP Standards and associated implementation timetables to facilities located at nuclear power plants8

6 On September 15 2009 in compliance with Order No 706-B NERC filed the Implementation Plan for the implementation of Version 1 of the CIP Standards by generator owners and operators of nuclear power plants9 With the exception of CIP- para 61174 (2008) order on clarification Order No 706-B 126 FERC para 61229 (2009)

3 Order No 706 122 FERC para 61040 at P 25

4 Order No 706-B 126 FERC para 61229 at P 1

5 Id

6 Id P 60

7 North American Electric Reliability Corp 128 FERC para 61291 (2009) (September 30 Order)

8 Id P 13

9 NERC Sept 15 2009 Compliance Filing and Petition for Approval of Implementation Plan Docket No RM06-22-10 (NERC September 15 Petition)

Docket No RM06-22-010 - 3 -

002-1 R1 and R210 the Implementation Plan is structured such that the timelinecompliance for each requirement within the CIP Standards is the later of (i) the Commission-approved effective date of the Implementation Plan (designated as ldquoRrdquo) plus 18 months (R + 18 months) (ii) the date the scope of systems determination is completed (designated as ldquoSrdquo) plus 10 months (S + 10 months) or (iii) if an outage is required for implementation six months following the completion of the first refueling outage at least 18 months following the Commissionrsquos effective date

for

11 NERC stated that the ldquoscope of systems determinationrdquo includes establishing the NERC and NRC jurisdictional delineation for systems structures and components12 that is predicated upon the completion of a NERC-NRC memorandum of understanding as well as the creation of an exemption process for excluding certain systems structures and components from the scope of NERC CIP Standards as provided for in Order No 706-B13

7 By order issued on December 17 2009 the Commission requested that NERC submit additional information regarding the scope of systems determination to assist the Commissionrsquos evaluation of the Implementation Plan14 Specifically we directed NERC to provide the following information to help the Commission evaluate whether the Implementation Plan provides an appropriate schedule to make the CIP Standards mandatory and enforceable for generator owners and operators of US nuclear power plants

the anticipated date the scope of systems determination framework will be finalized

the status of the development of the exemption process

10 CIP-002-1 R1 and R2 pertain to the identification of critical assets which is a

preliminary step for implementing of the remainder of the CIP Standards Accordingly the Implementation Plan calls for CIP-002-1 R1 and R2 to be completed within 12 months of the Commission-approved effective date of the Implementation Plan See NERC September 15 Petition at Exhibit A 3

11 Id at Exhibit A 2

12 The phrase ldquostructures systems and componentsrdquo refers to any element of equipment systems or networks of equipment or portions within a nuclear power plant within an entityrsquos ownership or control See Order No 706-B at P 15

13 See NERC Petition at Exhibit A 2 see also Order No 706-B at P 50

14 December 17 Order 129 FERC para 61224 at P 2 and 14

Docket No RM06-22-010 - 4 -

whether the exemption process will include (i) an application deadline and (ii) a deadline for a determination on an exemption request and

a description of any other time parameters that may be included in the exemption process15

In addition the Commission directed NERC to make a compliance filing incorporating into the Implementation Plan the implementation of Version 2 of the CIP Standards by nuclear power plants on the same schedule established for Version 116

II NERC Compliance Filing

8 In response to the Commissionrsquos information request NERCrsquos January 19 Compliance Filing explains its process for making the scope of systems determination and provides a project timeline for completing the scope of systems determination17 According to NERCrsquos Compliance Filing it will use a ldquoBright-Line Testrdquo to make its scope of systems determination18 The Bright-Line Test will identify which systems structures and components in a nuclear power plantrsquos balance of plant are subject to NERCrsquos CIP Standards and which are subject to the NRCrsquos jurisdiction In its Compliance Filing NERC reiterates its request that the Commission approve the Implementation Plan as it relates to the implementation of Version 1 of the CIP Standards with an immediate effective date

9 NERC stated in its September 15 2009 Petition that the scope of systems determination would be predicated upon the completion of a memorandum of understanding (MOU) between NERC and the NRC The MOU was executed on December 30 200919 The MOU sets forth and coordinates NERCrsquos and the NRCrsquos

(continuedhellip)

15 Id P 14

16 Id P 15

17 NERC January 19 2010 Compliance Filing in Response to the Commissionrsquos December 17 2009 Order Addressing Compliance Filing and Requiring Further Compliance Filing (Compliance Filing)

18 NERCrsquos Compliance Filing appears to use the terms ldquoBright-Line Testrdquo ldquoBright-Line exemption processrdquo and ldquoBright-Line determinationrdquo interchangeably to refer to the ldquoexemption processrdquo NERC has developed to make its scope of systems determination

19 Compliance Filing at 6 NERC submitted a copy of the MOU as Exhibit 1 to

Docket No RM06-22-010 - 5 -

respective roles and responsibilities related to the application of each of their cyber security requirements20 Under the rubric of the MOU NERC and NRC are collaborating on the development of an ldquoin-scoperdquo system list to clarify which systems structures and components at nuclear power facilities will be subject to NRCrsquos security regulations and which will be subject to the CIP Reliability Stand 21

cyber ards

10 According to NERC to make the scope of systems determination using its Bright-Line Test NERC will follow a two part process First NERC will conduct workshops followed by the Bright-Line documentation process Specifically NERC states that it plans to conduct a series of regional workshops for nuclear plants licensed by the NRC (licensees) to facilitate the development of a Bright-Line Survey and to communicate expectations for licenseesrsquo completion of the Survey22 At the workshops NERC will present a preliminary Bright-Line Survey that the licensees will modify to the specifics of their respective facilities The Survey is intended to gather detailed information about each licenseersquos systems structures and components and will require the licensees to identify all systems structures and components with cyber assets Shortly after the workshops NERC will distribute the Bright-Line Survey to each licensee The completed surveys will be due back to NERC within 30 days Beginning in June or July of 2010 NERC will verify the survey results through facility site visits if necessary Once verified NERC and the NRC will use the survey results to make the scope of systems determination

A Date the Scope of Systems Determination Framework Will Be Finalized

11 With respect to the anticipated date the scope of systems determination framework will be finalized NERC states that it plans to finalize the scope of systems determinations within 8 months of the date the Implementation Plan becomes effective (referred to by NERC as ldquoR + 8 monthsrdquo) This projected timeframe is based on the assumption that the effective date for the Implementation Plan will be April 1 2010 This timeline would ensure that there would be no significant gap between the compliance date linked to the Commission effective date (scenario (i) under the Implementation Plan R + 18) and the compliance deadline linked to the scope of systems

the Compliance Filing

20 See MOU at I3

21 Compliance Filing at 6

22 Id at 7-8

Docket No RM06-22-010 - 6 -

determination (scenario (ii) under the Implementation Plan S + 10) NERC further notes that the scope of systems determination may be later for entities with requirements tied to a specific plant outage

B Status of the Development of the Exemption Process

12 In response to the Commissionrsquos question regarding the status of the development of the exemption process NERC states that the exemption process ie the Bright-Line Test started with the planning of the regional workshops NERCrsquos Bright-Line determination project timeline broken down by task is included with its Compliance Filing as Exhibit 2

C Whether the Exemption Process Includes Deadlines for Applications and Determinations

13 With regard to whether the exemption process will include an application deadline or a determination deadline NERC states that there will be a deadline for submitting ldquothe necessary informationrdquo presumably the Bright-Line Survey Based on NERCrsquos statement that ldquothe determination of a Licenseesrsquo scope of systems to be exempted from compliance with the NERC CIP Reliability Standards must be made no later than R + 8 monthsrdquo23 it appears that NERC intends to complete the exemption process within eight months of the Commission-approved effective date for the Implementation Plan According to NERC this timeframe will ensure that the compliance deadline for licensees subject to a scope of systems determination will track the standard compliance deadline ie R + 18 months

D Other Time Parameters

14 In response to the question regarding any other time parameters that may be included in the exemption process NERC notes that its projected schedule is ldquocontingent upon NRC resourcesrdquo24

E Implementation of Version 2 and 3 of the CIP Standards

15 In response to the Commissionrsquos directive regarding the inclusion of the implementation of Version 2 of the CIP Standards into the Implementation Plan NERC requests permission to submit an additional compliance filing requesting Commission approval of the Version 2 and Version 3 implementation plans for US nuclear owners

23 Id at 9

24 Id at 9-10

Docket No RM06-22-010 - 7 -

and operators after the plans have been balloted by the industry and approved by the NERC Board of Trustees NERC states that it is in the process of developing the CIP Version 2 and 3 implementation plans for nuclear facilities but could not complete the balloting process within the 30 day compliance deadline set by the December 17 Order NERC asserts that the deadline for US nuclear power plant ownersrsquo and operatorsrsquo compliance with the Version 2 and Version 3 CIP Standards will mirror the Implementation Plan for Version 1 of the CIP Standards as required by the December 17 Order25 In addition NERC states that it ldquowill include for all future filings of proposed new versions of the CIP-002 through CIP-009 standards an associated Implementation Plan that addresses US Nuclear Power Plant Owners and Operators compliance to the proposed requirementsrdquo26

III Notice and Responsive Pleadings

16 Notice of NERCrsquos Compliance Filing was published in the Federal Register with interventions and protests due on or before February 9 201027 On February 9 2010 Exelon Corporation (Exelon) filed comments

17 Exelon notes that NERCrsquos plan for completing the Bright-Line determination does not include a contingency for delays Thus Exelon is concerned with NERCrsquos assertion that ldquothe determination of a Licenseesrsquo scope of systems to be exempted from compliance with the NERC CIP Reliability Standards must be made no later then R + 8 monthsrdquo28 Exelon states that NERCrsquos ldquoformula R + 8 months may not give licensees the full time intendedrdquo to seek an exemption29 Exelon asserts that licensees must know what systems are subject to NERCrsquos jurisdiction before they can invoke NERCrsquos exemptions process to avoid dual regulation To resolve this issue Exelon requests that the Commission condition its approved effective date (R) on the actual date that the Bright-Line determination is finalized

18 Exelon raises two additional concerns First Exelon states that the Bright-Line determination may conflict with the NRCrsquos Critical Digital Asset assessment process noting that as the NRCrsquos Critical Digital Asset assessments progress ldquothe rationale for

25 Id at 11

26 Id at 10

27 75 Fed Reg 4374 (Jan 27 2010)

28 Exelon Comments (quoting Compliance Filing at 9)

29 Id

Docket No RM06-22-010 - 8 -

NERC exemptions may become more clearly definedrdquo30 To alleviate this concern Exelon requests that the Commission direct NERC either to consider the timing of the NRCrsquos Critical Digital Asset assessment process in its Bright-Line determination plan or to provide for an ongoing exemptions process in lieu of a finite completion date Second Exelon ldquorequests that NERC provide clear guidance on the scope of the proposed [Bright-Line] surveyrdquo and asks that the Commission direct NERC to extend the 30 day deadline for licensees to complete the survey31

IV Commission Determination

19 In the December 17 Order we stated that the ldquogeneral structure of the Implementation Plan comports with the directives in Order No 706-Brdquo32 However because the Implementation Plan is structured such that the compliance date is the later of three scenarios one of which is tied to the completion of NERCrsquos scope of systems determination absent information regarding NERCrsquos scope of systems determination the Commission could not determine whether the implementation timeline established an adequate degree of finality for compliance with the CIP Standards NERCrsquos January 19 2010 Compliance Filing provides a description of NERCrsquos process for determining the scope of systems that must comply with the NERC CIP Standards and those systems that fall under the NRCrsquos regulations The Commission is not reviewing NERCrsquos scope of systems determination process itself ie the Bright-Line Test as the Commission in Order No 706-B left it to the ERO to formulate and implement an ldquoexceptions processrdquo33 Rather the Commission is evaluating whether NERCrsquos exemption process the scope of systems determination will unduly delay the date the CIP Standards become mandatory and enforceable for nuclear power plant licensees

30 Id at 4

31 Id

32 December 17 Order 129 FERC para 61224 at P 14

33 Order No 706-B 126 FERC para 61229 at P 50 (holding that with respect to the delineation of which balance of plant equipment may be subject to the NRC cyber security regulation ldquo[t]he Commission believes that with the above two-part approach ie subjecting all balance of plant equipment within a nuclear power plant to the CIP Reliability Standards with exceptions allowed via a process implemented by the ERO nuclear power plant licensees will have a bright-line rule that eliminates the potential regulatory gap and provides certainty and a plant-specific equipment exception process to avoid dual regulation where appropriaterdquo)

Docket No RM06-22-010 - 9 -

20 The Commission finds that NERCrsquos process for the scope of systems determination the Bright-Line Test along with NERCrsquos projected timeline for completing the Bright-Line Test provides for a final determination that will be made with a reasonable timeframe We note that while NERC states that it intends to finalize the scope of systems determination within eight months of the date the Implementation Plan becomes effective there remains the possibility that NERC will not meet that schedule NERC itself notes that the implementation schedule is ldquocontingent upon NRC resourcesrdquo34 For that reason the Commission remains concerned about potential delays in the compliance date Accordingly the Commission accepts NERCrsquos compliance filing and approves NERCrsquos Implementation Plan for US nuclear power plant ownersrsquo and operatorsrsquo compliance with Version 1 of the CIP Standards However should NERC become aware that it will be unable to complete the scope of systems determinations within NERCrsquos projected timeframe (R + 8 months) NERC must timely notify the Commission of the reason for the delay and propose an alternate deadline

21 Exelon requests that in recognition of the potential for delays in the scope of systems determination the Commission ldquocondition the effective date of its approval of NERCrsquos CIP Version 1 Implementation Plan for nuclear generator owners and operators based on the actual date that NERC and the NRC finalize the Bright-Line determinationrdquo35 The Commission finds that Exelonrsquos concern does not warrant action In the first instance NERC should meet the implementation schedule it has proposed and we approve in this order However as stated above NERC must notify the Commission give reason and propose an alternative deadline if it is unable to meet its projected timeframe of R + 8 months We believe this adequately resolves Exelonrsquos concern

22 Further Exelonrsquos request is unnecessary given the existing structure of the Implementation Plan As the Commission understands Exelonrsquos request Exelon wants the effective date of the Implementation Plan to be tied to the date NERC and the NRC complete the scope of systems determination The Implementation Plan is structured such that the compliance date is the latter of three scenarios one of which is tied to the date the scope of systems determination is completed Thus the CIP Standards will not become mandatory and enforceable against generator owners and operators of nuclear plants until at a minimum 10 months after the date NERC completes the scope of systems determination (designated as S + 10 months in the Implementation Plan) regardless of when the scope of systems determination is concluded Under this

34 Compliance Filing at 9-10

35 Exelon Comments at 4-5

Docket No RM06-22-010 - 10 -

structure if NERCrsquos scope of systems determination (ie completion of the Bright-Line test) is delayed the compliance deadline will also be delayed In other words NERCrsquos projected timeframe of R + 8 months36 for completing the scope of systems determination does not affect the amount of time licensees will have to become compliantwith the CIP

Standards

23 With respect to Exelonrsquos remaining concerns the Commission believes that they are beyond the scope of this order In this proceeding the Commission is ruling on the timeline of the proposed Implementation Plan and the adequacy by which it will ensure timely compliance with the CIP Standards The Commission has left the specific details of the development and implementation of the scope of systems determination to the discretion of the NRC and NERC

24 Last with respect to NERCrsquos request to submit after completion of its balloting process its compliance filing establishing implementation plans for Version 2 and Version 3 of the CIP Standards the Commission grants NERCrsquos request NERC is directed upon completion of its balloting process to make a compliance filing submitting implementation plans for the implementation of Versions 2 and 3 of the CIP Standards by owners and operators of US nuclear power plants on the same schedule established for Version 1 under the Implementation Plan

The Commission orders

(A) NERCrsquos compliance filing is hereby accepted as discussed in the body of this order

(B) NERCrsquos Implementation Plan governing ownersrsquo and operatorsrsquo of US nuclear power plants implementation of Version 1 of the CIP Standards CIP-002-1 through CIP-009-1 is hereby approved as discussed in the body of this order effective as of the date of this order

(C) NERC is hereby directed upon completion of its balloting process related to the implementation plans applicable to generator owners and operators of US nuclear power plants for Versions 2 and 3 of the CIP Standards to make a compliance filing submitting implementation plans for the implementation of Versions 2 and 3 of the CIP

36 ldquoRrdquo is the Commission-approved effective date of the Implementation Plan

Docket No RM06-22-010 - 11 -

Standards by owners and operators of US nuclear power plants on the same schedule established for Version 1 under the Implementation Plan as discussed in the body of this order

By the Commission ( S E A L )

Kimberly D Bose Secretary

116-390 Village Blvd Princeton NJ 08540

6094528060 | wwwnerccom116-390 Village Boulevard Princeton New Jersey 08540-5721

Phone 6094528060 Fax 6094529550 wwwnerccom

Standard Authorization Request Form Title of Proposed Standard Project 2009-02 Real-time Reliability Monitoring and Analysis Capabilities

Original Request Date June 4 2009

Revised Date January 15 2010

Revised Date March 31 2010

SAR Requester Information SAR Type (Check a box for each one

that applies)

Name Jack Kerr New Standard(s) X

Primary Contact Dominion Virginia Power Revision to existing Standard X

Telephone 18042733393

Fax 18042732405

Withdrawal of existing Standard

E-mail jackkerrdomcom Urgent Action

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

The new or revised standard(s) will establish requirements for the functionality performance and change managementmaintenance of Real-time Monitoring and Analysis capabilities for Reliability Coordinators Transmission Operators Generator Operators and Balancing Authorities for use by their System Operators in support of reliable System operations

Standards Authorization Request Form

SARndash2

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)

According to the Final Report on the August 14 2003 Blackout in the United States and Canada Causes and Recommendations dated April 2004 a principal cause of the August 14 blackout was a lack of situational awareness which was in turn the result of inadequate reliability tools In addition the failure of control computers and alarm systems incomplete tool sets and the failure to supply network analysis tools with correct System data on August 14 contributed directly to this lack of situational awareness Also the need for improved visualization capabilities over a wide geographic area has been a recurrent theme in blackout investigations

Recommendation 22 of the Blackout Report states ldquoEvaluate and adopt better real-time tools for operators and reliability coordinatorsrdquo NERCrsquos Operating Committee formed the Real-time Tools Best Practices Task Force (RTBPTF) to evaluate real-time tools and their usage within the industry The Task Force produced a report ldquoReal-Time Tools Survey

Analysis and Recommendationsrdquo dated March 13 2008 that included recommendations for the functionality performance and management of Real-time tools

There are 2 directives in FERC Order 693 relating to minimum tool capabilities that need to be addressed One directive pertains to IRO-002 and is described in paragraphs 905 amp 906 of Order 693 The second directive pertains to TOP-006 and is described in paragraph 1660 These directives clearly indicate the desire for a minimum set of capabilities as opposed to specific tools The existing projects that would have handled these issues (Project 2006-02 for IRO-002 and Project 2007-03 for TOP-006) have clearly indicated that they expect this SAR (Project 2009-02) to address the issues raised by FERC

This SAR addresses selected recommendations in the RTBPTF Report as determined by the Real-time Best Practices Standards Study Group Project 2009-02 and addresses the directives in Order 693 referenced above

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

The scope of the SAR is to establish requirements for the monitoring and analysis capabilities provided to System Operators and used to support Real-time System Operations The SAR addresses availability parameters performance metrics and procedures for failure notification maintenance coordination and change management The intent is to describe lsquowhatrsquo needs to be done but not lsquohowrsquo to do it

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

Develop or revise standard(s) to describe the capability characteristics such as availability parameters performance metrics and procedures for failure notification and maintenance


SARndash3

coordination and change management (vetted by the industry through the Reliability Standards comment process)of functionality for

bull bull Monitoring power System data in Real-time

bull Exchanging power System data in Real-time

bull Emitting Real-time visible and audible signals to aAlerting System Operators in Real-time to events and conditions affecting the state of the Bulk Electric System (BES) This functionality shall include an independent process monitor (eg watchdog)

bull Determining the current state of the BES

bullEvaluating the impact of lsquowhat ifrsquo events on the current or future state of the BES

bull


SARndash4

Reliability Functions

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

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

Reliability Coordinator

X 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 gtone year plan for the resource adequacy of its specific loads within a Planning Coordinator area

Transmission Planner

Develops a gtone year plan for the reliability of the interconnected Bulk Electric System within its portion of the Planning Coordinator area

Transmission Service Provider

Administers the transmission tariff and provides transmission services under applicable transmission service agreements (eg the pro forma tariff)

Transmission Owner

Owns and maintains transmission facilities

X Transmission Operator

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

Distribution Provider

Delivers electrical energy to the End-use customer

Generator Owner

Owns and maintains generation facilities

X Generator Operator

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

Purchasing-Selling Entity

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

Market Operator

Interface point for reliability functions with commercial functions

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

Load-Serving Entity


SARndash5


6094528060 | wwwnerccom

Reliability and Market Interface Principles

Applicable Reliability Principles (Check box for all that apply)

1 X 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 X 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 X

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 X

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 X

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

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

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

1

(Select lsquoyesrsquo or lsquonorsquo from the drop-down box)

2

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

3

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

4

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


Standards Authorization Request

7

Related Standards

Standard No Explanation

TOP-xxx The TOP family of standards is undergoing revision The eventual SDT should have the flexibility to revise these standards or write new standards as best fits the task

IRO-xxx The IRO family of standards is undergoing revision The eventual SDT should have the flexibility to revise these standards or write new standards as best fits the task

COM-001-11 The eventual SDT should have the flexibility to revise this standard or write new standards as best fits the task

BAL-xxx

The BAL family of standards should be included in the scope of this SAR because they do address reliability-based data Therefore the eventual SDT should have the flexibility to revise these standards or write new standards as best fits the task

Related SARs

SAR ID Explanation

Regional Variances

Region Explanation

ERCOT

FRCC

MRO

NPCC

SERC

RFC

SPP

WECC

Concept White Paper Concepts for Proposed Content of Eventual Standard(s) for Project 2009-02 Real-Time Monitoring and Analysis Capabilities

Real-time Monitoring and Analysis Capabilities Standard Drafting Team February 15 2011

2 of 9

10

INTRODUCTION

FERC Order 693 indicates the need for a minimum set of capabilities to be available for System Operators to assist in making Real-time decisions The work done by the Real-time Tools Best Practices Task Force (RTBPTF) which was formed by NERC in response to the Final Report on the August 14 2003 Blackout in the United States and Canada Causes and Recommendations is the basis for the Real-time Monitoring and Analysis Capabilities SAR that was approved by the Standards Committee in April 2010 and the subsequent appointment by NERC of a Standard Drafting Team (RMACSDT) to develop a standard to satisfy the proposed issues described in the SAR utilizing the results-based standards methodology This White Paper is a description of the present thinking of the RMACSDT regarding standard requirements for Real-time monitoring and analysis capabilities The paper consists of four sections that describe the major areas proposed to be addressed by the eventual standard(s) These areas are Section 2 - Monitoring Section 3 - Data exchange Section 4 - Alarming Section 5 ndash Analysis

The SDT will also be crafting an Implementation Plan for any eventual standard(s) that will be vetted by the industry through comments and that will allow for sufficient time for applicable entities to bring their systems into compliance with any new requirements

20

MONITORING

Monitoring is the first component in the process of establishing situational awareness for the System Operators so that they can rapidly assess the state of the Bulk Electric System (BES) In the context of this standard ldquomonitoringrdquo implies System Operators viewing data in a manner that allows them to determine the state of the BES in Real-time and to take corrective and preventive actions when necessary The types of data to be considered by the standard are Real-time analog and status

o Scanned o Calculated

For purposes of monitoring as described in this paper this is data scanned by a central system from Data Collection Units (DCU) such as Remote Terminal Units (RTUs) Calculated values are treated the same as scanned values in this paper It is proposed that requirements for monitoring will be applicable to Reliability Coordinators Transmission Operators and Balancing Authorities

3 of 9

The following requirements are proposed for monitoring of Real-time data These requirements assume that the Responsible Entity is utilizing an Energy Management System (EMS) andor Supervisory Control and Data Acquisition (SCADA) system to collect the Real-time data

21 PERFORMANCE A performance parameter is proposed for each category of data collected and the data displayed to the operator

211 Status Data Status data shall be collected at a scan rate not to exceed 4 seconds

212 Analog Data In many systems analog data is collected at multiple scan rates depending on the applications in which the data is being used It is proposed that all analog data except the data identified in the BAL standards is scanned at a rate not to exceed 10 seconds - the rate suggested in the RTBPTF report

213 Data Display All active displays utilized for visualization of the data discussed above shall update by the end of the next status or analog scan cycle as stated above following the scan in which the data was received by the central system For example status data should be updated within 4 seconds following the receipt of the scan by the central system

22 AVAILABILITY The SDT proposes two requirements for availability A demonstrable procedure shall be developed describing the alternate plans andor

mitigating measures entities have in place when the data used to monitor BES or perform analyses on BES (see Section 5) becomes unavailable

For each DCU availability shall be calculated by dividing the number of ldquogoodrdquo scans

received at the central system by the number of scans scheduled to be received in a calendar month (A lsquogoodrsquo scan is a complete packet of requested data returned to the central system) The ratio of scans received to scans scheduled shall exceed 99 for a

4 of 9

calendar month This calculation can include alternate or backup data sources that provide data when the primary DCU is unavailable

23 FAILURE NOTIFICATION lsquoFailurersquo is assumed to occur when a scan is not completed for any reason and it shall be notified after the 9th consecutive lsquofailurersquo occurs The System Operator shall be notified of such failure within 60 seconds of the 9th

consecutive lsquofailurersquo

24 MAINTENANCE Each Responsible Entity shall provide the System Operator with approval authority for planned maintenance that impact monitoring capabilities

30

DATA EXCHANGE

Data exchange as discussed in this paper refers to electronic exchange of data between two computer based control systems (EMS andor SCADA) whether they are internal or external to each other It is assumed that the data links discussed will utilize ICCP or an equivalent protocol Data exchange in this context does not include RTUs or other similar types of DCUs Required data sets to be exchanged are covered in proposed IRO-010-2 and TOP-003-2 ICCP is the Inter-Control Center Communications Protocol (ICCP or IEC 60870-6TASE2 or latest release) It is an international standard used by utility organizations to provide data exchange over wide area networks (WANs) between utility control centers utilities power pools regional control centers and Non-Utility Generators Collecting and exchanging real-time data on power system status is one of the elementary steps in the complex process of developing the information that System Operators need to maintain situational awareness Real-time reliability tools such as the state estimator and contingency analysis can only provide results that accurately represent current and potential reliability problems if these tools have Real-time analog and status data The accuracy of the information that Real-time reliability tools provide depends on the accuracy of the data supplied to the tools The quality of the results that Real-time reliability tools produce is also influenced by the breadth and depth of the portion of the BES for which Real-time data are collected relative to the breadth and depth of the relevant Reliability Entityrsquos area of responsibility It is proposed that requirements for data exchange will be applicable to the Reliability Coordinator Transmission Operator Balancing Authority and Generation Operator

5 of 9

The following requirements are proposed for data exchange of Real-time data These requirements assume that the Responsible Entity is utilizing an EMS andor SCADA system utilizing ICCP or an equivalent protocol to exchange data

31 PERFORMANCE The SDT proposes the following requirements for data exchange performance ICCP (or equivalent) data exchange must be redundant and the redundancy must be

supplied through diverse routing

Entities shall develop data exchange agreements and comply with data specifications Data exchange agreements must include the following

bull Interoperability of ICCP and equivalent systems bull Data access restrictions bull Data naming conventions bull Data management and coordination including data quality bull Joint testing and data checkout bull Monitoring of availability bull Responsibility for failures bull Restoration process

32 AVAILABILITY The SDT proposes the following requirements for data exchange availability Establish procedure for actions to be taken if some or all of the data exchanged is not

available for a 30 minute timeframe

33 FAILURE NOTIFICATION Notification of link failure must be made to the System Operator within 60 seconds of when link failure occurred Failure is identified as the inability to receive a complete data set regardless of reason

34 MAINTENANCE Each functional entity shall provide System Operators with approval authority for planned maintenance of its data exchange capabilities Coordination with affected entities is required

6 of 9

40

ALARMING

Alarms must be generated to alert System Operators in Real-time to events and conditions affecting the state of the BES Alarms can be audible andor visual Alarms must be generated for the following reasons

bull Limit violations (for any defined limits including multiple limits on a single point)

bull Uncommanded status changes bull DCU unavailability bull Data exchange link unavailability

Alarms are important to the safe and secure operation of the BES System Operators depend on alarms to identify problems occurring or about to occur All values measured or calculated by the EMS andor SCADA must be subject to processing to determine either change of state or limit violations If either of these conditions occurs an alarm must be generated It is proposed that requirements for alarming will be applicable to Reliability Coordinators Transmission Operators and Balancing Authorities The following requirements are proposed for alarming of measured and calculated data

41 PERFORMANCE Performance issues such as volume and throughput of alarms are recognized as potential concerns but are generally handled in initial EMSSCADA vendor specifications It would be difficult if not impossible to measure in a production system Therefore no performance requirement is anticipated as part of this project

42 AVAILABILITY The SDT proposes the following requirements for alarming availability

bull No specific numeric value will be proposed for alarming availability bull Establish a procedure for actions to be taken when the alarming functionality is

unavailable for 10 consecutive minutes (see RTBPTF report page 117 paragraph 4) For example the Reliability Coordinator lsquobacks uprsquo the Transmission OperatorBalancing Authority and vice versa and entities inform each other of failure of their alarming capability

7 of 9

43 FAILURE NOTIFICATION Notification of failure of the alarm processing function must be made to the System Operator within 60 seconds of when failure is detected Notification of failure of alarming capability must be accomplished through independent failure notification where the system creating and presenting the notification is independent of the alarming functionality

44 MAINTENANCE Each functional entity shall provide System Operators with approval authority for planned maintenance of its alarming capabilities

50

ANALYSIS

The intent of analysis in the context of this white paper is to focus on determining the current condition or state of the BES and evaluate the impact of lsquowhat ifrsquo events on the state of the BES The meanings of ldquocurrentrdquo and ldquowhat-ifrdquo are

bull Current - The current system condition or state is a function of the most recent system bus voltages system topology frequency and line flows

bull lsquoWhat ifrsquo - Analyze the impact on the security of the current power system state of

specific Contingencies or simulated outages of the BES such as lines generators or other equipment This analysis should also include other system condition changes that would affect the BES such as Load The analysis identifies problems such as line overloads or voltage violations that will occur if the system event or Contingency takes place

The capability to determine the current state of the BES is critical for the System Operator to determine violations of reliability criteria in their area By accurately determining the current state of the BES the System Operator is thus capable of evaluating various lsquowhat ifrsquo scenarios Having the results of the lsquowhat ifrsquo events before they happen allows System Operators to take the appropriate actions to prevent violations or have plans ready if such Contingencies were to occur It is proposed that requirements for analysis will be applicable to the Reliability Coordinator and Transmission Operator The following requirements are proposed for analysis of the current and ldquowhat-ifrdquo states of the BES

8 of 9

51 PERFORMANCE The requirements for Performance will address periodicity and quality

511 Periodicity The current and ldquowhat-ifrdquo analyses shall run based on the following conditions

bull Current analysis - Automated program required that runs periodically at no more than a 5 minute interval to determine the systemrsquos current condition or state The analysis may be either a program that runs on the Reliability Coordinatorrsquos or Transmission Operatorrsquos EMS or through contracted services (3rd

party Reliability Coordinator or other Transmission Operator)

bull ldquoWhat ifrdquo analysis - Automated program required that runs periodically at no more than a 10 minute interval (from pg 117 of Blackout Report - 4b) to analyze the impact on the security of the current power system state for specific Contingencies or simulated outages of the BES such as lines generators or other equipment The analysis may be either a program that runs on the Reliability Coordinatorrsquos or Transmission Operatorrsquos EMS or through contracted services (3rd


512 Results Quality

Quality needs to be measured to ensure that the base case used by the automated analysis program(s) accurately represent the state of the system

bull For both current amp ldquowhat ifrdquo analyses

o For Reliability Coordinator amp Transmission Operator

o Compare physical lsquotiersquo line values and generator injections plus selected interconnected transmission line flows from the automated analysis program(s) to actual metered values every time the program runs These values have been selected because of the accuracy of the metering at those locations and their impact on the BES

o Compute the percentage deviation of the program values versus actual metered values

o Compute the average of the percentages on a periodic basis and compare to the tolerance value (Actual periodicity will be selected based on industry feedback)

o Tolerance must be +- x (Actual value will be selected based on industry feedback)

9 of 9

52 AVAILIBILITY Responsible entities must establish a procedure for what to do if the program(s) is not available for more than 30 consecutive minutes Current - The automated programs must provide a solution every five minutes 99 of the time on a monthly basis lsquoWhat ifrsquo - The automated programs must provide a solution every ten minutes 99 of the time on a monthly basis

53 FAILURE NOTIFICATION Notification of failure of the analysis capability to provide a solution to the System Operator must be made to the System Operator within 60 seconds of when failure is detected

54 MAINTENANCE Each functional entity shall provide System Operators with approval rights for planned maintenance of its analysis capabilities

From scottvidlerHydroOnecomTo Lee R PedowiczSubject RE RSC Meeting--March 16-17 2011Date Monday February 28 2011 25358 PM

Hi LeeEven though we posted the white paper to solicit industry feedback so that we couldconsider them in the drafting of the standard we donrsquot expect the project to continue at thistime NERC has performed an analysis of the outstanding standards that are in the hopperand used a prioritizing method to attempt to get the most important standards movingtowards completion At this time the Real-time Reliability Monitoring and AnalysisCapabilities standard is not going to make this yearrsquos active project list We will collect thedata from the white paper and the team members will be able to use it to guide any of ourdiscussions and when we reconvene hopefully we will be able to come out of the blocksand do a 100 metre dash to the finishI can certainly join a conference call ndash but there will not be much to say Irsquom available onMarch 17RegardsScott VidlerManager - Grid OperationsOperating Performance amp Customer SupportOntario Grid Control CentreHydro One Networks IncPhone 7057923020Cell 7056271436Internet scottvidlerhydroonecomGood ideas are not adopted automatically They must be driven into practice with courageous patience mdash HymanRickoverldquoThis e-mail and any attached files are privileged and may contain confidential information intended only for the person or personsnamed above Any other distribution reproduction copying disclosure or other dissemination is strictly prohibited If you havereceived this e-mail in error please notify the sender immediately by reply e-mail and delete the transmission received by yourdquo

From Lee R Pedowicz [mailtolpedowicznpccorg] Sent Monday February 28 2011 100 PMTo VIDLER ScottCc Guy V Zito Gerard J DunbarSubject RSC Meeting--March 16-17 2011 Good afternoon Scott At our upcoming NPCC RSC Meeting March 16-17 2011 we discuss the NERC Standards that areposted for comment or under development I checked our information and it lists you as being amember of the Drafting Team for Project 2009-02 - Real-time Reliability Monitoring and AnalysisCapabilities Being that it will still be posted when we have our meeting would you be able to callin and give us a summary of its status Our meeting is from 1000 am until 500 pm March 16and then 800 am until 300 pm on March 17 Wersquoll arrange our agenda for you Thanks

Lee PedowiczManager Reliability StandardsNPCCThis email and any of its attachments may contain information that is privilegedconfidential classified as CEII or subject to copyright belonging to NPCC This email isintended solely for the use of the individual or entity to which it is addressed If you are notthe intended recipient of this email you are hereby notified that any disseminationdistribution copying or action taken in relation to the contents of and attachments to thisemail is strictly prohibited and may be unlawful If you receive this email in error pleasenotify the sender immediately and permanently delete the original and any copy of this emailand any printout

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Informal Comment Period Open - Project 2009-02 Real-time Monitoring and Analysis CapabilitiesDate Wednesday February 16 2011 30000 PM

Standards AnnouncementProject 2009-02 Real-time Monitoring and Analysis CapabilitiesInformal Comment Period OpenFebruary 16 ndash April 4 2011 Now available at httpwwwnerccomfilezstandardsProject2009-02_Real-Time_Monitoring_Analysis_Capabilitieshtml Informal Comment Period Open through 8 pm on Monday April 4 2011The Project 2009-02 Real-time Monitoring and Analysis Capabilities Standard Drafting Team has posted for a 45-day informal commentperiod a White Paper on proposed concepts to support the development of real-time monitoring and analysis standards The White Paperalong with an unofficial Word version of the comment form have been posted on the project Web page athttpwwwnerccomfilezstandardsProject2009-02_Real-Time_Monitoring_Analysis_Capabilitieshtml InstructionsPlease submit comments using the electronic form Next StepsThe drafting team will consider the input received on the concept White Paper as it begins preparing to draft standards Project BackgroundThe need for improved visualization capabilities over a wide geographic area has been a recurrent theme in blackout investigationsAccording to the Final Report on the August 14 2003 Blackout in the United States and Canada Causes and Recommendations dated April2004 a principal cause of the August 2003 blackout was a lack of situational awareness a result of inadequate reliability tools NERCrsquos Operating Committee formed the Real-time Tools Best Practices Task Force (RTBPTF) to evaluate real-time tools and their usagewithin the industry The Task Force produced a report ldquoReal-Time Tools Survey Analysis and Recommendationsrdquo dated March 13 2008that included recommendations for the functionality performance and management of real-time tools This project addresses recommendations from the August 2003 Blackout Report the RTBPTF report and two directives from FERC Order693 Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate

For more information or assistance please contact Monica Benson at monicabensonnercnet

North American Electric Reliability Corporation



---You have received this email because you are a registered representative in the Registered Ballot Body

From Elizabeth HeenanTo Elizabeth HeenanSubject Comment Period Opens for Proposed Changes to ReliabilityFirst Corporation Rules of Procedure Pertaining to Regional Standards Development ProcessDate Tuesday March 01 2011 63525 PM

Comment Period Opens for Proposed Changes to ReliabilityFirstCorporationrsquos Rules of Procedure ndash Regional Standards DevelopmentProcess NERC Stakeholders Now available at httpwwwnerccomfilesFinal_Posting_RFC_Standards_Process_Changes_20110301pdf

NERC requests comments on the proposed revisions to ReliabilityFirst Corporationrsquos reliability standards development procedure OnJanuary 14 2011 NERC received a request from ReliabilityFirst Corporation to modify its proposed regional standard developmentprocess changes approved by the ReliabilityFirst Corporation Board of Directors In accordance with Section 311 of the NERC Rules of Procedure NERC is required to publicly notice and request comment on anyproposed changes to a regional standards development procedure for a minimum 45-day comment period Any objections identified bystakeholders during the posting period shall be resolved by ReliabilityFirst Corporation before the proposed changes are presented to theNERC Board of Trustees for approval Upon NERC Board of Trustee approval NERC shall file the proposed changes pursuant to 18 CFRsect 3910 (2010) with the Federal Energy Regulatory Commission for approval Materials Included in this Request for Comments

Letter from Timothy R Gallagher to David Cook outlining process and changes Attachment A- ReliabilityFirst Corporation Reliability Standards Development Procedure ndashVersion 3 (Clean) Attachment B - ReliabilityFirst Corporation Reliability Standards Development Procedure ndashVersion 3 (Redline) and Attachment C ndash Corresponding changes to Exhibit C to ReliabilityFirst Regional Delegation Agreement (Redline)

Comments are due April 15 2011 and must be submitted electronically to ropcommentsnercnet

For more information or assistance please contact Elizabeth Heenan at elizabethheenannercnet



6094528060 | wwwnerccom ---You are currently subscribed to nerc-info as lpedowicznpccorgTo unsubscribe send a blank email to leave-1249731-3256541ca6f85fb1574a8515cc07df72d3bfe0listservnerccom



Notice of Proposed Changes to RFC Rules of Procedure and Request for Comments

Proposed Changes to ReliabilityFirst Corporation Rules of Procedure Comments Due April 15 2011 The North American Electric Reliability Corporation (ldquoNERCrsquo) hereby requests comments on the proposed revisions to ReliabilityFirst Corporationrsquos reliability standards development procedure On January 14 2011 NERC received a request from ReliabilityFirst Corporation to modify its proposed regional standard development process changes approved by the ReliabilityFirst Corporation Board of Directors NERC has determined that ReliabilityFirst Corporationrsquos proposed regional reliability standards development procedure meets the criteria included in Section 31131 of the NERC Rules of Procedure (open inclusive balanced due process and transparent) In accordance with Section 311 of the NERC Rules of Procedure NERC is required to publicly notice and request comment on any proposed changes to a regional standards development procedure for a minimum 45-day comment period Any objections identified by stakeholders during the posting period shall be resolved by ReliabilityFirst Corporation before the proposed changes are presented to the NERC Board of Trustees for approval Upon NERC Board of Trustee approval NERC shall file the proposed changes pursuant to 18 CFR sect 3910 (2010) with the Federal Energy Regulatory Commission for approval

Materials Included in this Request for Comments

- Letter from Timothy R Gallagher to David Cook outlining process and changes - Attachment A- ReliabilityFirst Corporation Reliability Standards Development Procedure ndashVersion 3

(Clean) - Attachment B - ReliabilityFirst Corporation Reliability Standards Development Procedure ndashVersion

3 (Redline) and - Attachment C ndash Corresponding changes to Exhibit C to ReliabilityFirst Regional Delegation

Agreement (Redline) Submission of Comments Comments are due April 15 2011 and must be submitted electronically to ropcommentsnercnet NERC intends to submit the proposed changes to the ReliabilityFirst standards development procedure to the NERC Board of Trustees for approval at its May 11 2011 meeting For further information please contact Elizabeth Heenan at elizabethheenannercnet

320 SPRINGSIDE DRIVE SUITE 300 AKRON OH 44333-4500 (330) 456-2488 Fax (330) 456-5408

January 14 2011 Mr David Cook Senior Vice President and General Counsel North American Electric Reliability Corporation Princeton Forrestal Village 116-390 Village Boulevard Princeton NJ 08540-5721 Dear David Please find attached to this letter the revised Standards Development Procedure (the ldquoProcedurerdquo) of ReliabilityFirst Corporation (ldquoReliabilityFirstrdquo) reflecting revisions to the Procedure approved by the Board of Directors of ReliabilityFirst on December 15 2010 (Attachments A and Bmdashclean and redlined versions) and a redline version of Exhibit C (Attachment C) to the Regional Delegation Agreement (ldquoRDArdquo) The redline Exhibit C is included to demonstrate that the revisions to the Procedure continue to adhere to the Attributes specified in Exhibit C for the development of Regional Reliability Standards ReliabilityFirst revised the Procedure to improve the openness of the process to increase the requirement on affirmative votes to align with the North American Electric Reliability Corporation (ldquoNERCrdquo) process to better align the ReliabilityFirst process with the NERC process and to improve clarity and understanding of the process With this filing ReliabilityFirst seeks to satisfy the requirements of the Federal Energy Regulatory Commissionrsquos (ldquoFERCrdquo or the ldquoCommissionrdquo) regulations regarding changes to Regional Entity Rules As specified in 18 CFR sect 391 (2010) the Standards Development Procedure of a Regional Entity such as ReliabilityFirst are Regional Entity Rules As such the Commissionrsquos regulations require that NERC as the Electric Reliability Organization must approve any modifications or revisions to the Procedure and then submit any approved modifications or revisions to the Commission for approval 18 CFR sect 3910 (2010) and North American Electric Reliability Council et al 119 FERC para 61060 at P 333 (2007) The Commissionrsquos regulations require that when NERC submits changes in Regional Entity Rules to the Commission NERC must explain ldquothe basis and purpose for the Rule or Rule change together with a description of the proceedings conducted by the Regional Entity to develop the proposalrdquo 18 CFR sect 3910 (2010) To assist NERC in complying with this requirement and to aid NERC in its independent consideration of the revisions to the Procedure ReliabilityFirst is supplying the information requested by the regulations

Timothy R GallagherPresident and Chief Executive Officer

Direct Dial (330) 247-3040timgallagherrfirstorg

2

I The Basis and Purpose for the Revisions to the Procedure

A Substantive Revisions The revised Procedure contains the following substantive revisions

1 Include an informal Standard Authorization Request (ldquoSARrdquo) comment period step

a Added a SAR comment step to assist the ReliabilityFirst Standards Committee (ldquoSCrdquo) in determining if the SAR should move into the standard drafting phase

2 Make the Category Ballot approval percentage consistent with NERC (super-majority

vs simple majority

a Changed the approval percentage to two-thirds or greater

3 Modifications to the voting and Ballot Pool structure

a Modified the voting and Ballot Pool structure to further align with the NERC process

b Corporations or organizations will be able to cast one vote in each ReliabilityFirst registered voting category as long as a different individual is registered in each registered voting category If a corporation or organization is registered in each one of the ReliabilityFirst voting categories the maximum number of votes possible is five including corporation and organization affiliates

4 Inclusion of a Recirculation Ballot period

a A Recirculation Ballot period will be required if ReliabilityFirst received any negative ballot comments during the initial 15-Day Category Ballot

b The addition of a recirculation ballot will give stakeholders the opportunity to review the comments submitted by other entities during the initial Category Ballot to determine if they wish to reconsider their voting position

5 Inclusion of an informal comment period within the Interpretation section

a Added an informal comment period to the Interpretation section which will increase the transparency of the Procedure and allow stakeholders to weigh in on interpretations developed by ReliabilityFirst

6 Inclusion of language referencing the use of the NERC Standards Template

a Added additional language referencing the use of NERC Standards Template to allow ReliabilityFirst standards and NERC standards to follow a consistent format and template


7 Further clarification regarding ldquoEffective Datesrdquo

a Added language to further clarify ldquoEffective Datesrdquo for ReliabilityFirst standards

i ReliabilityFirst standards are mandatory and enforceable without monetary penalties for non-compliance upon the effective date for applicable entities that are members of ReliabilityFirst

ii ReliabilityFirst standards are mandatory and enforceable with monetary penalties for non-compliance for all applicable registered entities within the ReliabilityFirst footprint upon approval by the Commission

B Changes to Correct TypographicalTechnical Issues The revised Procedure contains the following minor revisions

8 Removal of references to the ldquoInterim Compliance Committee (ldquoICCrdquo) from the Interpretation section since the ICC no longer exists

9 A number of format and editorial changes to further clarify certain sections II Proceedings Conducted by ReliabilityFirst to Revise the Procedure

ReliabilityFirst followed the current FERC-approved Standards Development procedure to develop the revisions submitted with this filing See 119 FERC para 61060 at P 339 Specifically on January 20 2010 the SC authorized a SAR to modify two specific items of the Procedure The scope of the SAR consisted of items 1 and 2 above On April 30 2010 the SC authorized a supplemental SAR (based on the recommendation of the ReliabilityFirst Standard Drafting Team) in which the scope consisted of the remaining items identified above Upon completion of the items listed in the two SARs ReliabilityFirst posted the revised Standards Procedure for one 30-Day Comment period (June 16 2010 through July 15 2010) in which a total of 17 commenters provided comments After responding to all comments and modifying the Procedure accordingly ReliabilityFirst posted the Procedure for the required 15-Day period prior to Category Ballot (August 17 2010 through August 31 2010) followed by the 15-Day Category Ballot (September 1 2010 through September 15 2010)

The Procedure passed the 15-Day Category Ballot achieving quorum (972) with an overwhelming affirmative category vote (100) Following the Category Ballot the Procedure was publically posted for the required 30 days prior to ReliabilityFirst Board action (September 24 2010 through October 23 2010) The ReliabilityFirst Board of Directors unanimously approved the Procedure on December 15 2010

4

III Conclusion ReliabilityFirst believes these revisions do not affect its delegated authority under 18 CFR sect 398 ReliabilityFirst respectfully requests that NERC consider and approve the foregoing amendments to the ReliabilityFirst Standards Development Procedure and submit the revised Procedure to the Commission for its approval as changes to the rules of a Regional Entity in accordance with 18 CFR sect 3910

Sincerely RELIABILITYFIRST CORPORATION Timothy R Gallagher President and Chief Executive Officer

cc Susan O Ivey ReliabilityFirst Corporation Chair Board of Directors Kenneth Defontes ReliabilityFirst Corporation Vice-Chair Board of Directors Larry E Bugh ReliabilityFirst Corporation Director of Corporate Affairs L Jason Blake ReliabilityFirst Corporation Corporate Counsel Anthony E Jablonski ReliabilityFirst Corporation Standard Process Manager

Attachment A ReliabilityFirst Standards Development Procedure

Revised December 15 2010

(Clean)

ReliabilityFirst Corporation Reliability Standards Development

Procedure Version 3

ReliabilityFirst Board Approval December 15th 2010


ReliabilityFirst Corporation Reliability Standards Development Procedure

Table of Contents

Introduction 1 Background 2 Regional Reliability Standard Definition Characteristics and Elements 3 Roles in the Regional Reliability Standards Development Process 7 Regional Reliability Standards Development Process 8 Appendix A Maintenance of Regional Reliability Standards Development Processhelliphelliphellip17 Appendix B Standard Authorization Request 21 Appendix C Flowchart for Standards Process 28 Appendix D Ballot Pool Categories and Registration 30


Introduction This procedure establishes the process for adoption of a Regional Reliability Standard1 (hereinafter referred to as ldquoStandardrdquo) of the ReliabilityFirst Corporation (ReliabilityFirst) and the development of consensus for adoption approval revision reaffirmation and deletion of such Standards1 ReliabilityFirst Standards provide for the reliable regional and sub-regional planning and operation of the Bulk Power System2 (BPS) consistent with Good Utility Practice2 within the ReliabilityFirst geographical footprint This procedure was developed under the direction of the ReliabilityFirst Board of Directors (Board) who may request changes to this ReliabilityFirst Reliability Standards Development Procedure (hereinafter referred to as ldquothis Procedurerdquo) as deemed appropriate A procedure for revising this Procedure is contained in Appendix A This Procedure is consistent with the North American Electric Reliability Corporation (NERC) Reliability Standards Development Procedure ReliabilityFirst standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA The approval date of each ReliabilityFirst standard is upon ReliabilityFirst Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 The ReliabilityFirst standard is mandatory and enforceable (with monetary penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint upon approval by FERC The effective date for non-members upon the FERC approval will be determined by the implementation plan that is provided with each new or revised standard ReliabilityFirst Standards shall provide for as much uniformity as possible with NERC reliability standards across the interconnected BPS A ReliabilityFirst Standard shall be more stringent than a NERC reliability standard including a regional difference that addresses matters that the NERC reliability standard does not or shall be a regional 1 Legacy standards such as ECAR Documents MAIN Guides and MAAC Procedures shall be considered ReliabilityFirst Regional Reliability Standards for the purposes of this document until otherwise acted upon by the ReliabilityFirst Board 2 As defined in the ReliabilityFirst By-laws 3 By applying for and becoming a Regular or Associate Member of the Corporation each Member agrees to comply with all Reliability Standards all NERC standards and requirements and the other obligations of Members of the Corporation set forth in the ReliabilityFirst Bylaws or duly adopted by the Board in order to achieve the purposes of the Corporation

ReliabilityFirst Board Approval December 15th 2010 Page 1 of 31

difference necessitated by a physical difference in the BPS A ReliabilityFirst Standard that satisfies the statutory and regulatory criteria for approval of proposed NERC reliability standards and that is more stringent than a NERC reliability standard would generally be acceptable ReliabilityFirst Standards when approved by FERC shall be made part of the body of NERC reliability standards and shall be enforced upon all applicable BPS owners operators and users within the ReliabilityFirst area regardless of membership in the region Background Regions may develop through their own processes separate ldquoRegional Standardsrdquo (ReliabilityFirst Standards) that go beyond add detail to or aid implementation of NERC reliability standards or otherwise address issues that are not addressed in NERC reliability standards As a condition of ReliabilityFirst membership all ReliabilityFirst Members2 agree to adhere to the NERC reliability standards As such the ReliabilityFirst and its Members will adhere to the NERC reliability standards in addition to the ReliabilityFirst Standards NERC reliability standards and the ReliabilityFirst Standards are both to be included within the ReliabilityFirst Compliance Program

ReliabilityFirst Standards are intended to apply only to that part of the Eastern Interconnection within the ReliabilityFirst geographical footprint The development of these ReliabilityFirst Standards is developed according to the following principles via the process contained within this Procedure

bull Developed in a fair and open process that provided an opportunity for all interested parties to participate

bull Does not have an adverse impact on commerce that is not necessary for reliability

bull Provides a level of BPS reliability that is adequate to protect public health safety welfare and national security and would not have a significant adverse impact on reliability and

bull Based on a justifiable difference between Regions or between sub-Regions within the Regional geographic area

2 As defined in the ReliabilityFirst By-laws


Regional Reliability Standard Definition Characteristics and Elements Definition of a Reliability Standard

As contained in the ReliabilityFirst By-laws ReliabilityFirst ldquoRegional Reliability Standardrdquo shall mean a type of Reliability Standard that is applicable only within a particular Regional Entity or group of Regional Entities A Regional Reliability Standard may augment add detail to or implement another Reliability Standard or cover matters not addressed by other Reliability Standards Regional Reliability Standards upon adoption by NERC and approval by the Commission enforced within the applicable Regional Entity or Regional Entities pursuant to delegated authorities Inherent in this definition a ReliabilityFirst Standard will define certain obligations or requirements of entities that own operate plan and use the BPS within the ReliabilityFirst geographical footprint These obligations or requirements as contained in the ReliabilityFirst Standards are to be measurable and consistent with Good Utility Practice Standards are not to include processes or procedures that implement a Standard In addition obligations requirements or procedures imposed upon ReliabilityFirst by NERC reliability standards are not to be ReliabilityFirst Standards unless those obligations requirements or procedures require the establishment of a ldquopolicy or standardrdquo as defined by the ReliabilityFirst By-laws Characteristics of a Regional Reliability Standard A Standard is policy including adequacy criteria to provide for the reliable regional and sub-regional planning and operation of the BPS consistent with Good Utility Practice A Standard shall generally have the following characteristics

bull Measurable - A Standard shall establish technical or performance requirements that can be practically measured

bull Relative to NERC Reliability Standards - A Standard generally must go

beyond add detail to or implement NERC Reliability Standards or cover matters not addressed in NERC Reliability Standards

Format Requirements of a Regional Reliability Standard A Standard shall consist of the requirements shown in the Regional Reliability Standard Template These requirements apply to the development and revision of Standards These requirements are necessary to achieve Standards that are measurable enforceable and consistent Supporting documents to aid in the implementation of a Standard may be referenced by the Standard but are not part of the Standard itself The most current version of the approved NERC Reliability Standard template and its associated elements


posted on the NERC website will be used at the time of the development of a ReliabilityFirst Regional Reliability Standard if different from the elements listed below

Regional Reliability Standard Format Requirement Template Example Identification Number

A unique identification number assigned in accordance with an administrative classification system to facilitate tracking and reference ReliabilityFirst documentation

Title A brief descriptive phrase identifying the topic of the Standard

Applicability Clear identification of the functional classes of entities responsible for complying with the Standard noting any specific additions or exceptions If not applicable to the entire ReliabilityFirst area then a clear identification of the portion of the BPS to which the Standard applies Any limitation on the applicability of the Standard based on electric facility requirements should be described

Effective Date and Status

The effective date of the Standard or prior to approval of the Standard the proposed effective date

Purpose The purpose of the Standard The purpose shall explicitly state what outcome will be achieved or is expected by this Standard

Requirement(s) Explicitly stated technical performance and preparedness requirements Each requirement identifies what entity is responsible and what action is to be performed or what outcome is to be achieved Compliance is mandatory for each statement in the requirements section


Risk Factor(s)

The potential reliability significance of each requirement designated as a High Medium or Lower Risk Factor in accordance with the criteria listed below A High Risk Factor requirement (a) is one that if violated could directly cause or contribute to BPS instability separation or a cascading sequence of failures or could place the BPS at an unacceptable risk of instability separation or cascading failures or (b) is a requirement in a planning timeframe that if violated could under emergency abnormal or restorative conditions anticipated by the preparations directly cause or contribute to BPS instability separation or a cascading sequence of failures or could place the BPS at an unacceptable risk of instability separation or cascading failures or could hinder restoration to abnormal condition A Medium Risk Factor requirement (a) is a requirement that if violated could directly affect the electrical state or the capability of the BPS or the ability to effectively monitor and control the BPS but is unlikely to lead to BPS instability separation or cascading failures or (b) is a requirement in a planning timeframe that if violated could under emergency abnormal or restorative conditions anticipated by the preparations directly affect the electrical state or capability of the BPS or the ability to effectively monitor control or restore the BPS but is unlikely under emergency abnormal or restoration conditions anticipated by the preparations to lead to BPS instability separation or cascading failures nor to hinder restoration to a normal condition A Lower Risk Factor requirement is administrative in nature and (a) is a requirement that if violated would not be expected to affect the electrical state or capability of the BPS or the ability to effectively monitor and control the BPS or (b) is a requirement in a planning time frame that if violated would not under the emergency abnormal or restorative conditions anticipated by the preparations be expected to affect the electrical state or capability of the BPS or the ability to effectively monitor control or restore the BPS

Measure(s) Each requirement shall be addressed by one or more measurements that will be used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measurement identifies to whom the measurement applies Each measurement shall be tangible and as objective as is practical Achieving the full compliance level of each measurement is a necessary and sufficient indicator that the requirement was met

Compliance Administration Elements


Compliance Monitoring Process

Defines for each measure bull The specific data or information that is required to measure

performance or outcomes bull The entity that is responsible to provide the data or information

for measuring performance or outcomes bull The process that will be used to evaluate information for the

purpose of assessing performance or outcomes bull The entity that is responsible for evaluating information to assess

performance or outcomes bull The time period in which performance or outcomes is measured

evaluated and then reset bull Data retention requirements and assignment of responsibility for

data archiving bull Violation severity levels


Supporting Information Elements Interpretations Any ReliabilityFirst interpretations of the Standards that were

developed and approved in accordance with the ldquoInterpretation of Standardsrdquo section of this Procedure to expound on the application of the Standard for unusual or unique situations or provide clarifications

Implementation Plan

Each ReliabilityFirst Standard shall have an associated implementation plan describing the effective date of the Standard or effective dates if there is a phased implementation The implementation plan may also describe the implementation of the Standard in the compliance program and other considerations in the initial use of the Standard such as necessary tools training etc The implementation plan must be posted for at least one public comment period and be approved as part of the ballot of the standard

Supporting References

This section references related documents that support reasons for or provide additional information related to the Standard Examples include but are not limited to bull Glossary of Terms bull Developmental history of the Standard and prior versions bull Subcommittee(s) responsible for Standard bull Notes pertaining to implementation or compliance bull Standard references bull ProceduresPractices bull Training andor Technical Reference

Roles in the Regional Reliability Standards Development Process Process Roles Originator - Any entity (person organization company government agency individual etc) that is directly and materially affected by the reliability of the ReliabilityFirst BPS is allowed to request a Standard be developed or an existing Standard is modified or deleted by creating a Standards Authorization Request (SAR) See Appendix B Board ndash The ReliabilityFirst Board shall act on any proposed Standard that has gone through the process contained in this Procedure Once the ReliabilityFirst Board approves a Standard compliance with the Standard will be enforced consistent with the By-laws and the terms of the Standard Standards Committee (SC) - The ReliabilityFirst SC will consider which requests for new or revised Standards shall be assigned for development (or existing Standards considered for deletion) The SC manages the Standards development process The SC


will advise the ReliabilityFirst Board on Standards presented for adoption by the ReliabilityFirst Board Standards Process Manager (SPM) ndash A person or persons on the ReliabilityFirst staff assigned the task of ensuring that the development revision or deletion of Standards is in accordance with this Procedure The SPM works to ensure the integrity of the process and consistency of quality and completeness of the Standards The SPM facilitates the administration of all actions contained in all steps in the process Standards Process Staff ndash Employees of the ReliabilityFirst that work with or for the SPM Standard Drafting Team (SDT) ndash A team of technical experts and typically including a member of the ReliabilityFirst Standards staff and the Originator assigned the task of developing a proposed Standard based upon an approved SAR using the Standard development process contained in this Procedure Ballot Body (BB) ndash The Ballot Body comprises all entities that qualify for one or more of the categories and are registered with ReliabilityFirst as potential ballot participants in the voting on standards The categories of registration within the Ballot Body and the registration process are described in Appendix D Ballot Pool ndash The Ballot Pool is comprised of those members of the Ballot Body that register to vote for each particular standard A separate Ballot Pool is established for each standard up for vote Only individuals who have joined the Ballot Pool for that particular standard are eligible to vote on a standard Reliability Committee (RC) ndash The ReliabilityFirst RC serves as a technical advisory body to address the reliability related activities required by the Reliability Standards via review and discussion of the regional activities as requested by the SC Regional Reliability Standard Development Process (Flow chart of Process shown in Appendix C) Assumptions and Prerequisites The ReliabilityFirst Regional Reliability Standards Development Process has the following characteristics

bull Fair due process - The ReliabilityFirst standards development process shall provide for reasonable notice and opportunity for public comment At a minimum the procedure shall include public notice of the intent to develop a standard a public comment period on the proposed standard due consideration of those public comments and a ballot of interested stakeholders


bull Openness - Participation is open to all Organizations who are directly and materially affected by the ReliabilityFirst region BPS reliability There shall be no undue financial barriers to participation Participation shall not be conditioned upon membership in the ReliabilityFirst and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements Meetings of SDTs are open to the ReliabilityFirst membership and to others

bull Balanced - The ReliabilityFirst standards development process

strives to have an appropriate balance of interests and shall not be dominated by any two interest categories and no single interest category shall be able to defeat a matter

bull Inclusive - Any entity (person organization company government

agency individual etc) with a direct and material interest in the BPS in the ReliabilityFirst area shall have a right to participate by a) expressing a position and its basis b) having that position considered and c) having the right to appeal

bull Transparent - All actions material to the development of

ReliabilityFirst Standards shall be transparent All standards development meetings shall be open and publicly noticed on ReliabilityFirstrsquos Web site

bull Does not unnecessarily delay development of the proposed Standard

Note The term ldquodaysrdquo refers to calendar days

Each standard shall enable or support one or more of the reliability principles thereby ensuring that each standard serves a purpose in support of the reliability of the regional BPS Each standard shall also be consistent with all of the reliability principles thereby ensuring that no standard undermines reliability through an unintended consequence While ReliabilityFirst Standards are intended to promote reliability they must at the same time accommodate competitive electricity markets Reliability is a necessity for electricity markets and robust electricity markets can support reliability Recognizing that BPS reliability and electricity markets are inseparable and mutually interdependent all ReliabilityFirst Standards shall be consistent with NERCrsquos market interface principles Consideration of the market interface principles is intended to ensure that standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets ReliabilityFirst will coordinate with NERC such that the acknowledgement of receipt of a standard request identified in step 1 notice of comment posting period identified in step 4 and notice for vote identified in step 5 below are concurrently posted on both the ReliabilityFirst and NERC websites


Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete a Regional Reliability Standard Any individual representing an organization (Originator) which is directly or materially impacted by the operation of the BPS within the geographical footprint of the ReliabilityFirst may request via a submittal of a Standard Authorization Request (SAR) form the development modification or deletion of a ReliabilityFirst Standard Any such request shall be submitted to the ReliabilityFirst SPM or hisher designee or by another process as otherwise posted on the ReliabilityFirst website The SAR form may be downloaded from the ReliabilityFirst website The SAR contains a description of the proposed Standard subject matter containing sufficiently descriptive detail to clearly define the purpose scope impacted parties and other relevant information of the proposed Standard The SPM will verify that the submitted SAR form has been adequately completed The SPM may offer the Originator suggestions regarding changes andor improvements to improve clarity and assist the ReliabilityFirst community to understand the Originatorrsquos intent and objectives The Originator is free to accept or reject these suggestions Within 15 days the SPM will electronically acknowledge receipt of the SAR The SPM will forward the adequately complete SAR to the ReliabilityFirst SC at which time the SC will post the SAR for comments within 15 days SARs will be posted and publicly noticed Comments on the SARs will be accepted for a 30-day period from the notice of posting Comments will be accepted online using an internet-based application The SPM will provide a copy of the comments to the Originator and the SC Based on the comments the SC shall make available a consideration of comments report and determine the disposition of the SAR (within 60 calendar days following the SAR commenting period) The disposition decision and decision process shall use the normal ldquobusiness rules and proceduresrdquo of the SC then in effect The SC may take one of the following actions3 in accordance with the ReliabilityFirst Standards Committee Governance document

bull Accept the SAR as a candidate for development of a new Standard revision of an existing Standard or deletion of an existing Standard The SC may in its sole discretion expand or narrow the scope of the SAR under consideration The SC shall prioritize the development of SARs as may be required based on the number of SARs under development at any time

bull Reject the SAR If the SC rejects a SAR a written explanation for rejection will

be delivered to the Originator within 30 days of the decision

3Actions by the Standards Committee may be appealed per the Appeals process in Appendix A


bull Remand the SAR back to the Originator for redirection to the NERC process In cases where there is a Reliability need identified in the SAR but it does not meet the criteria for Regional standards (more stringent reliability requirements than the NERC reliability standard or cover matters not covered by an existing NERC reliability standard) the Standards Committee will assist the Originator in submitting the SAR to NERC

bull Remand the SAR back to the Originator for additional work The SPM will make

reasonable efforts to assist the Originator in addressing the deficiencies identified by the SC The Originator may then resubmit the modified SAR using the process above The Originator may choose to withdraw the SAR from further consideration prior to re-submittal to the SC

Any SAR that is accepted by the SC for development of a Standard (or modification or deletion of an existing Standard) shall be posted for public viewing on the ReliabilityFirst website within 30 days of acceptance by the SC The status of posted SARs will be publicly posted Any documentation of the deliberations of the SC concerning SARs shall be made available according to the ldquoReliabilityFirst Standards Committee Governancerdquo document then in effect The SC shall submit a written report to the ReliabilityFirst Board on a periodic basis (at least at every regularly scheduled ReliabilityFirst Board meeting) showing the status of all SARs that have been brought to the SC for consideration Step 2 ndash Formation of the Standard Drafting Team and Declaration of Milestone Date Upon acceptance by the SC of a SAR for development of a new Standard (or modification or deletion of an existing Standard) the SC shall direct the SPM to develop a qualified balance slate for the SDT using the specific directions and preferences of the SC The SPM will send out self-nomination forms to solicit SDT nominees The SDT will consist of a group of people (members of ReliabilityFirst and as appropriate non-members) who collectively have the necessary technical expertise and work process skills The SPM will recommend a slate of ad-hoc individuals or a preexisting task force work group or similar for the SDT based upon the SCrsquos desired SDT capabilities The SC may also direct the SPM to designate an existing ReliabilityFirst committee (or subset thereof) as the SDT augmented by other persons as may be appropriate for the subject matter The SC will insure that SDT membership includes all necessary administrative support This support typically includes a ReliabilityFirst staff member and the Originator if heshe chooses to participate The SC appoints the interim chair (should not be a staff person) of the SDT The SDT will elect the permanent Chair and Vice-chair at its first meeting


The SPM submits the proposed list of names of the SDT to the SC The SC will either accept the recommendations of the SPM or modify the SDT slate as it deems appropriate within 60 days of accepting a SAR for development Upon approval of the SDT slate the SC will declare a preliminary date on which the SDT is expected to have ready a completed draft Standard and associated supporting documentation available for consideration by the ReliabilityFirst membership Step 3 ndash Work and Work Product of the Standard Drafting Team The SDT will then develop a work plan for completing the Standard development work including the establishment of milestones for completing critical elements of the work in sufficient detail to ensure that the SDT will meet the deadline established by the SC or the SDT shall propose an alternative date This plan is then delivered to the SC for its concurrence The SDT is to meet either in person or via electronic means as necessary establish sub-work teams (made up of members of the SDT) as necessary and performs other activities to address the parameters of the SAR and the milestone date(s) established by the SC The work product of the SDT will consist of the following

bull A draft Standard consistent with the SAR on which it was based bull An assessment of the impact of the SAR on neighboring regions and

appropriate input from the neighboring regions if the SAR is determined to impact any neighboring region

bull An implementation plan including the nature extent and duration of field-testing if any

bull Identification of any existing Standard that will be deleted in part or whole or otherwise impacted by the implementation of the draft Standard

bull Technical reports white papers andor work papers that provide technical support for the draft Standard under consideration

bull Document the perceived reliability impact should the Standard be approved

Upon completion of these tasks the SDT submits these documents to the SC which will verify that the proposed Standard is consistent with the SAR on which it was developed The SDT regularly (at least once each month) informs the SC of its progress in meeting a timely completion of the draft Standard The SDT may request of the SC scope changes of the SAR at any point in the Standard development process The SC may at any time exercise its authority over the Standards development process by directing the SDT to move to Step 4 and post for comment the current work product If there are competing drafts the SC may at its sole discretion post the version(s) of the


draft Standard for comment on the ReliabilityFirst website The SC may take this step at any time after a SDT has been commissioned to develop the Standard Step 4 ndash Comment Posting Period At the direction from the SC the SPM then facilitates the posting of the draft Standard on the ReliabilityFirst website along with a draft implementation plan and supporting documents for a 30-day comment period The SPM shall also inform ReliabilityFirst Members and other potentially interested entities inside or outside of ReliabilityFirst of the posting using typical membership communication procedures then currently in effect or by other means as deemed appropriate As early as the start of the first posting for comment entities may join the Ballot Pool established for the eventual voting on the proposed standard The Ballot Pool category description and associated requirements are in Appendix D Within 30 days of the conclusion of 30-day comment posting period the SDT shall convene and consider changes to the draft Standard the implementation plan andor supporting technical documents based upon comments received Based upon these comments the SDT may elect to return to step 3 to revise the draft Standard implementation plan andor supporting technical documentation The SDT shall prepare a ldquomodification reportrdquo summarizing the comments received and the changes made as a result of these comments The modification report also summarizes comments that were rejected by the SDT and the reason(s) that these comments were rejected in part or whole Responses to all comments will be posted on the ReliabilityFirst website no later than the next posting of the proposed Standard Step 5 ndash Posting for Voting by ReliabilityFirst Registered Ballot Body Upon recommendation of the SDT and if the SC concurs that all of the requirements for development of the Standard have been met the SPM will post the revised draft Standard implementation plan supporting technical documentation and the ldquomodification reportrdquo Once the notice for a vote has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued Entities may register in the BB at any time during the Standards process The BB category description and associated rules are in Appendix D By 1159 PM Central Prevailing Time (CPT) of the seventh day of the 15 day pre-ballot posting period registered BB members intending to vote on the proposed standard must have joined the Ballot Pool established for the eventual voting on the proposed standard being posted The SPM will schedule a Vote by the Ballot Pool which is to be scheduled to commence no sooner than 15 days and no later than 30 days following this posting The Vote by the Ballot Pool is an advisory to the ReliabilityFirst Board


The Ballot Pool shall be allowed to vote over a period of 15 days Votes will be submitted electronically but may be submitted through other means as approved by the SC All BB members are eligible to participate in voting on proposed new Standards Standard revisions or Standard deletions There is a requirement to join a Ballot Pool to participate in voting for each standard The voting results will be composed of only the votes from BB entities that have joined the Ballot Pool for the standard being voted on and responding within the voting period Votes may be accompanied by comments explaining the vote but are not required All comments shall be responded to and posted to the ReliabilityFirst website prior to going to the SC or Board Step 6A ndash Voting Receives Two-Thirds or Greater Majority of Affirmative Category Votes A two-thirds or greater majority4 of votes within a category determines the vote for that category The Initial ballot has passed if there is a two-thirds or greater affirmative majority of category votes (only those categories with votes cast will be considered) during the 15-day voting period and a quorum5 is met If there is at least one (1) Negative vote with comment during the initial ballot then the standard will be posted for a 10-day Recirculation ballot If there are no Negative votes with comments the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7) In the recirculation ballot members of the Ballot Pool shall again be presented the proposed standard (that has not been significantly changed from the previous ballot) along with the reasons for negative votes the responses and any resolution of the differences An insignificant revision is a revision that does not change the scope applicability or intent of any requirement and includes but is not limited to things such as correcting the numbering of a requirement correcting the spelling of a word adding an obviously missing word or rephrasing a requirement for improved clarity Where there is a question as to whether a proposed modification is ldquosubstantiverdquo the Standards Committee shall make the final determination All members of the Ballot Pool shall be permitted to reconsider and change their vote from the prior ballot Members of the Ballot Pool who did not respond to the prior ballot shall be permitted to vote in the recirculation ballot In the recirculation ballot Ballot Pool members may indicate a revision to their original vote otherwise their vote shall remain the same as in their prior ballot Upon successful completion of the initial and recirculation voting periods the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7)

4 For the purposes of determining majority within a category an abstention is not considered a vote 5 A quorum is achieved when three-fourths (75) or greater of the ballot pool casts a vote


Step 6B ndash Voting Does Not Receive Two-Thirds or Greater Majority of Affirmative Category Votes or a Quorum5 is Not Met If a draft Standard does not receive a two-thirds or greater affirmative majority of votes determined for each category (only those categories with votes cast will be considered) or does not reach quorum during the 15-day Initial voting period the SC may

Direct the SDT to respond to ballot comments and post the standard for a 10-day Recirculation ballot (as discussed in Step 6A) to determine if the response to comments alleviates reasons for the Negative initial ballots

Direct the existing SDT to reconsider or modify certain aspects of the draft

Standard andor implementation plan The resulting draft Standard andor implementation plan will be posted for a second initial voting period The SC may require a second comment period prior to the second voting period The second posting of the draft Standard implementation plan and supporting documentation shall be within 60 days of the SC action

o If there is a two-thirds or greater affirmative majority of categories with

votes cast and a quorum is met during the second initial ballot and second recirculation ballot the SC will forward it to the ReliabilityFirst Board for action (Step 7)

o If a draft Standard does not receive a two-thirds or greater majority of

affirmative category votes cast during the second initial ballot or a quorum is not met the SC will refer the draft Standard and implementation plan to the ReliabilityFirst Board The SC may also submit an assessment opinion and recommendations to the ReliabilityFirst Board (Step 7)

bull Revise the SAR on which the draft Standard was based and remand the

development work back to the original SDT or a newly appointed SDT The resulting draft Standard andor implementation plan will be posted for a second voting period The SC may require a second comment period prior to a second voting period The second posting of the draft Standard implementation plan and supporting documentation shall be within 60 days of the SC action




affirmative category votes cast during the second voting period or a quorum is not met the SC will refer the draft Standard and implementation plan to the ReliabilityFirst Board The SC may also


submit an assessment opinion and recommendations to the ReliabilityFirst Board (Step 7)

bull Recommend termination of all work on the development of the Standard action

under consideration and so notify the ReliabilityFirst Board Step 7 ndash Action by the ReliabilityFirst Board A draft Standard submitted to the ReliabilityFirst Board for action must be publicly posted at least 30 days prior to action by the Board At a regular or special meeting the ReliabilityFirst Board shall consider adoption of the draft Standard The Board will consider the results of the voting and dissenting opinions The Board will consider any advice offered by the SC Draft Standards that received a two-thirds or greater of categories with votes cast shall be delivered to the ReliabilityFirst Board for their action The ReliabilityFirst Board shall be provided with an ldquoinformational packagerdquo which includes

bull The draft Standard and any modification or deletion of other related

existing Standard(s) bull Implementation Plan (including recommending field testing and effective

dates) bull Technical Documentation supporting the draft Standard bull A summary of the vote and summary of the comments and responses that

accompanied the votes

The ReliabilityFirst Board is expected to either

bull Approve the draft Standard action with only minor or no modification Under no circumstances may the Board substantively modify the proposed regional reliability standard

bull Remand to the SC with comments and instructions or bull Disapprove the draft Standard action without recourse

Draft Standards that did not receive a two-thirds or greater of categories with votes cast in the second voting period shall be delivered to the ReliabilityFirst Board for their action The ReliabilityFirst Board shall be provided with an ldquoinformational packagerdquo





Once a regional ReliabilityFirst Standard is approved by the Board the standard will be submitted to NERC for approval and filing with FERC Step 8 - Implementation of a Regional Reliability Standard The SPM will notify the membership upon ReliabilityFirst Board approval of the standard through the normal and customary membership communication procedures and processes then in effect The SPM will also notify the ReliabilityFirst Compliance Staff for integration into the ReliabilityFirst Compliance Program The approval date of each ReliabilityFirst standard is upon Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 ReliabilityFirst standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA Upon approval of a ReliabilityFirst standard action by FERC it is mandatory and enforceable (with monetary penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint The effective date for non-members upon the FERC approval will be determined by the implementation plan that is provided with each new or revised standard

3 By applying for and becoming a Regular or Associate Member of the Corporation each Member agrees to comply with all Reliability Standards all NERC standards and requirements and the other obligations of Members of the Corporation set forth in the ReliabilityFirst Bylaws or duly adopted by the Board in order to achieve the purposes of the Corporation


Appendix A Maintenance of Regional Reliability Standards Development Process Significant changes to this Procedure shall begin with the preparation of a SAR and be handled using the same procedure as a request to add modify or delete a Standard The ReliabilityFirst SC has the authority to make lsquominorrsquo changes to this Procedure as deemed appropriate by the SC and subject to the SC voting practices and procedures according to the ldquoReliabilityFirst Standards Committee Governancerdquo document The SC shall promptly notify the ReliabilityFirst Board of such lsquominorrsquo changes to this Procedure for their review and concurrence at the next ReliabilityFirst Board meeting Maintenance of Regional Reliability Standards The SC shall ensure that each Standard shall be reviewed at least once every five years from the effective date of the Standard or the latest revision to the Standard whichever is the later The review process shall be conducted by soliciting comments from the stakeholders If no changes are warranted the SC shall recommend to the ReliabilityFirst Board that the Standard be reaffirmed If the review indicates a need to revise or delete a Standard a SAR shall be prepared and submitted in accordance with the standards development process contained in this Procedure Urgent Action Under certain conditions the SC may designate a proposed Standard or revision to a Standard as requiring urgent action Urgent action may be appropriate when a delay in implementing a proposed Standard or revision could materially impact reliability of the BPS The SC must use its judgment carefully to ensure an urgent action is truly necessary and not simply an expedient way to change or implement a Standard A requester prepares a SAR and a draft of the proposed Standard and submits both to the SPM The SAR must include a justification for urgent action The SPM submits the request to the SC for its consideration If the SC designates the requested Standard or revision as an urgent action item then the SPM shall immediately post the draft for pre-ballot review This posting requires a minimum 30-day posting period before the ballot and applies the same voting procedure as detailed in Step 5 Processing will continue as outlined in the subsequent steps In the event additional drafting is required a SDT will be assembled as outlined in the Procedure Any Standard approved as an urgent action shall have a termination date specified that shall not exceed one year from the approval date Should there be a need to make the Standard permanent then the Standard would be required to go through the full Standard development process All urgent action Standards require ReliabilityFirst Board NERC and FERC approval as outlined for Standards in the regular process


Urgent actions that expire may be renewed using the urgent action process again in the event a permanent Standard is not adopted In determining whether to authorize an urgent action Standard for a renewal ballot the SC shall consider the impact of the Standard on the reliability of the BPS and whether expeditious progress is being made toward a permanent replacement Standard The SC shall not authorize a renewal ballot if there is insufficient progress toward adopting a permanent replacement Standard or if the SC lacks confidence that a reasonable completion date is achievable The intent is to ensure that an urgent action Standard does not in effect take on a degree of permanence due to the lack of an expeditious effort to develop a permanent replacement Standard With these principles there is no predetermined limit on the number of times an urgent action may be renewed However each urgent action Standard renewal shall be effective only upon approval by the ReliabilityFirst Board NERC and FERC Any person or entity including the SDT working on a permanent replacement Standard may at any time submit a SAR proposing that an urgent action Standard become a permanent Standard by following the full Standards process Interpretations of Standards All persons who are directly and materially affected by the reliability of ReliabilityFirst BPS shall be permitted to request an interpretation of the standard The person requesting an interpretation will send a request to the SPM explaining the specific circumstances surrounding the request and what clarifications are required as applied to those circumstances The request should indicate the material impact to the requesting party or others caused by the lack of clarity or a possibly incorrect interpretation of the standard The SPM along with guidance from the SC will assemble a team with the relevant expertise to address the request The Interpretation Drafting Team (IDT) typically consists of members from the original SDT The SPM submits the proposed list of names of the IDT to the SC The SC will either accept the recommendations of the SPM or modify the IDT slate As soon as practical (not more than 45 days) the team will prepare an initial draft interpretation of the standard addressing the issues raised Once the IDT has completed the initial draft interpretation the team will post the draft for a 30-day informal6 stakeholder comment period The IDT will review the stakeholder feedback and may make changes before preparing a final draft of the interpretation The IDT will then forward the draft interpretation to the SPM The SPM will forward the interpretation to the Reliability Committee (RC) Barring receipt of an opinion from the RC within 21 calendar days that the interpretation is not technically appropriate for the Standard

6 An informal comment period does not require the IDT to respond to every stakeholder comment and is only used to make potential changes for the final draft of the interpretation


respectively the SPM will forward the interpretation to the SC The SC will determine if the interpretation is consistent with the Standard and does not add additional requirements to the standard The SC will forward the interpretation to the ReliabilityFirst Board for informational purposes as being appended to the approved Standard Note In the event that the RC determines that the interpretation makes the standard technically inappropriate the RC shall provide an explanation of its reasoning to the SPM and IDT for inclusion in a subsequent revision In either case the IDT and SPM will continue to re-circulate the interpretation as stated above The interpretation will stand until such time as the standard is revised through the normal process at which time the standard will be modified to incorporate the clarifications provided by the interpretation Appeals Persons who have directly and materially affected interests and who have been or will be adversely affected by any substantive or procedural action or inaction related to the development approval revision reaffirmation or withdrawal of a Standard shall have the right to appeal This appeals process applies only to the Standards process as defined in this Procedure The burden of proof to show adverse effect shall be on the appellant Appeals shall be made within 30 days of the date of the action purported to cause the adverse effect except appeals for inaction which may be made at any time In all cases the request for appeal must be made prior to the next step in the process The final decisions of any appeal shall be documented in writing and made public The appeals process has two levels with the goal of expeditiously resolving the issue to the satisfaction of the participants Level 1 Appeal Level 1 is the required first step in the appeals process The appellant submits a complaint in writing to the SPM that describes the substantive or procedural action or inaction associated with a Standard or the standards process The appellant describes in the complaint the actual or potential adverse impact to the appellant Assisted by any necessary staff and committee resources the SPM shall prepare a written response addressed to the appellant as soon as practical but not more than 45-days after receipt of the complaint If the appellant accepts the response as a satisfactory resolution of the issue both the complaint and response will be made a part of the public record associated with the standard Level 2 Appeal


If after the Level 1 Appeal the appellant remains unsatisfied with the resolution as indicated by the appellant in writing to the SPM the SPM shall convene a Level 2 Appeals Panel This panel shall consist of five members total appointed by the ReliabilityFirst Board In all cases Level 2 Appeals Panel members shall have no direct affiliation with the participants in the appeal The SPM shall post the complaint and other relevant materials and provide at least 30-days notice of the meeting of the Level 2 Appeals Panel In addition to the appellant any person that is directly and materially affected by the substantive or procedural action or inaction referenced in the complaint shall be heard by the panel The panel shall not consider any expansion of the scope of the appeal that was not presented in the Level 1 Appeal The panel may in its decision find for the appellant and remand the issue to the SC with a statement of the issues and facts in regard to which fair and equitable action was not taken The panel may find against the appellant with a specific statement of the facts that demonstrate fair and equitable treatment of the appellant and the appellantrsquos objections The panel may not however revise approve disapprove or adopt a reliability standard The actions of the Level 2 Appeals Panel shall be publicly posted In addition to the foregoing a procedural objection that has not been resolved may be submitted to the ReliabilityFirst Board for consideration at the time the Board decides whether to adopt a particular reliability standard The objection must be in writing signed by an officer of the objecting entity and contain a concise statement of the relief requested and a clear demonstration of the facts that justify that relief The objection must be filed no later than 30-days after the announcement of the vote on the Standard in question


Appendix B Standard Authorization Request The SC shall be responsible for implementing and maintaining this form as needed to support the information requirements of the standards development process in this Procedure Changes to this form are considered minor and therefore subject to only the approval of the SC

ReliabilityFirst Standard Authorization Request Form

ReliabilityFirst will complete

ID

Authorized for Posting

Authorized for Development

Title of Proposed Standard

Request Date

SAR Originator Information

Name SAR Type (Check box for one of these selections)

Company

New Standard

Telephone Revision to Existing Standard

Fax Withdrawal of Existing Standard

E-mail Urgent Action

Purpose (Provide one or two sentences)

Industry Need (Provide one or two sentences)


Brief Description (A few sentences or a paragraph)


The Standard will Apply to the Following Functions (Check box for each one that applies) Reliability Authority Ensures the reliability of the bulk transmission system

within its Reliability Authority area This is the highest reliability authority

Balancing Authority Integrates resource plans ahead of time and maintains load-interchange-resource balance within its metered boundary and supports system frequency in real time

Generator Owner Owns and maintains generating units

Interchange Authority Authorizes valid and balanced Interchange Schedules

Planning Authority Plans the BPS

Resource Planner Develops a long-term (generally one year and beyond) plan for the resource adequacy of specific loads (customer demand and energy requirements) within a Planning Authority Area

Transmission Planner Develops a long-term (generally one year and beyond) plan for the reliability (adequacy) of the interconnected bulk electric transmission systems within its portion of the Planning Authority Area


Provides transmission services to qualified market participants under applicable transmission service agreements

Transmission Owner Owns transmission facilities

Transmission Operator Operates and maintains the transmission facilities and executes switching orders

Distribution Provider Provides and operates the ldquowiresrdquo between the transmission system and the customer


Generator Operator Operates generating unit(s) and performs the functions of supplying energy and Interconnected Operations Services

Purchasing-Selling Entity The function of purchasing or selling energy capacity and all necessary Interconnected Operations Services as required

Load-Serving Entity Secures energy and transmission (and related generation services) to serve the end user

Market Operator Integrates energy capacity balancing and transmission resources to achieve an economic reliability-constrained dispatch of resources The dispatch may be either cost-based or bid-based

Regional Reliability Organizations

An entity that ensures that a defined area of the BPS is reliable adequate and secure A member of the North American Electric Reliability Council The Regional Reliability Organization can serve as the Compliance Monitor

NOTE The SDT may find it necessary to modify the initial reliability function responsibility assignment as a result of the standards development and comments received

Reliability Principles Applicable Reliability Principles (Check box for all that apply)

1 Interconnected BPS 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 BPS 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 BPS 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 BPS 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 BPS

6 Personnel responsible for planning and operating interconnected BPS shall be trained qualified and have the responsibility and authority to implement actions

7 The security of the interconnected BPS shall be assessed monitored and maintained on a wide-area basis


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

Recognizing that reliability is an essential requirement of a robust North American economy

yes or no

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

yes or no

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

yes or no

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

yes or no

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


Detailed Description (Provide enough detail so that an independent entity familiar with the industry could draft a Standard based on this description)


Related Standards (NERC and Regional)


Related SARs




Description (Provide plans for the implementation of the proposed standard including any known systems or training requirements Include the reliability risk(s) associated with the violation that the standard will mitigate and the costs associated with implementation)

Proposed Implementation days after Board adoption or

on (date)

Assignments Assignment

Team Members ReliabilityFirst Staff


Appendix C Flowchart for Standards Process

Step 1

SC Action

Remand SAR

Accept SAR

Reject SAR

Post Request for

SDT

Step 2

Appoint SDT

Draft Standard Step 3

Edit Format Grammar Spelling

SC Authorizes 30-Day Posting for Comments Step 4

Posting of Draft Standard for Comments

SDT Convenes to Respond to

CommentsModify Standard

SAR Comment Period

Originator Submits SAR

to SPM

Remand SAR amp Redirect to NERC


Initial Category Vote

SC Action

Revise SAR

Terminate Standard

Direct SDT to Revise Standard

SC Assessment

File for NERCFERC approval and implement standard

throughout RFC footprint

2nd Category Vote

Two-Thirds or Greater

Affirmative


Affirmative

Yes No

Yes

No

SC Forwards to Board

Step 5 Step 6B

Step 6A

Step 7

Negative vote with comments

No

Recirculation Vote

Yes


Affirmative Yes

A

Implement standard for RFC member

companies

No

B

Yes

Board Approval

No

A

B

A

Step 8


Appendix D Ballot Pool Categories For the purposes of category Ballot Pool registration and voting a person or entity may join the registered Ballot Pool to vote on standards whether or not such person or entity is a member of ReliabilityFirst A corporation or other organization with integrated operations or with affiliates that qualifies to belong to more than one category (eg Transmission Owners and Load Serving Entities) may join and vote once in each category for which it qualifies provided that each category constitutes a separate membership in the Ballot Body and the organization is represented in each category by a different representative Affiliated entities are collectively limited to one membership in each category in the Ballot Pool for which they are qualified Category 1 ndash Transmission Owner Transmission Operator Transmission Service

Provider Category 2 ndash Generator Owner Generator Operator Category 3 ndash Load Serving Entity Purchasing and Selling Entity End User Category 4 ndash Reliability Coordinator Planning Coordinator Transmission Planner

Resource Planner Regional Transmission Organization Balancing Authority regulatory or governmental agency

Category 5 ndash Distribution Provider Ballot Body Registration Entities may register in the BB at any time during the Standards process The SPM shall review all applications for joining the BB and make a determination of whether they qualify for the self-selection category In order to comment or vote you must have an active membership in the BB When you submit your registration request to join the BB you are placed in a ldquopending stagerdquo until your account is activated Activation of your account may take up to 24 hours You will be unable to submit comments or join a Ballot Pool until your account is activated The contact designated as primary representative to ReliabilityFirst is the voting member with the secondary contact as the backup Note Registration for a BB is not the same as registration for the compliance registry Although the terminology used to describe the BB categories in most cases has the same meaning as the terms used in the NERC Functional Model registration in a BB goes beyond the compliance registry in that entities smaller than those stated in the compliance



registry guidelines are allowed to register in a BB Entities shall have evidence that they qualify for the BB category they register in Such evidence shall be available for the SPM review to verify BB registration and may include compliance registration Ballot Pool Formation In order to participate in voting on a particular standard an entity must join the Ballot Pool being established for the standard as follows 1 ndash As early as the start of the first posting for comment entities may join the Ballot Pool established for the eventual voting on the proposed standard being posted 2 - By close of business of the seventh day of the 15 day pre ballot posting period entities wishing to vote must have joined the Ballot Pool established for the eventual voting on the proposed standard being posted

Attachment B ReliabilityFirst Standards Development Procedure


(Redline)

ReliabilityFirst Reliability Standards Development Procedure Board Approval December 6th 2007 Standards Committee Modified April 1st 2008 - Board Concurrence May 22nd 2008


Procedure


ReliabilityFirst Reliability Standards Development Procedure Board Approval December 6th 200715th 2010 Standards Committee Modified April 1st 2008 - Board Concurrence May 22nd 2008

Formatted Font 10 pt



Version 3


Table of Contents

Introduction 1 Background 2 Regional Reliability Standard Definition Characteristics and Elements 3 Roles in the Regional Reliability Standards Development Process 7 Regional Reliability Standards Development Process 8 Appendix A Maintenance of Regional Reliability Standards Development Processhelliphelliphellip17





Appendix B Standard Authorization Request 21 Appendix C Flowchart for Standards Process 28 Appendix D Ballot Pool Categories and Registration 30

ReliabilityFirst Board Approval December 6th 200715th 2010 Standards Committee Modified April 1st 2008 - Board Concurrence May 22nd 2008

Page 1 of 31




Introduction This procedure establishes the process for adoption of a Regional Reliability Standard1 (hereinafter referred to as ldquoStandardrdquo) of the ReliabilityFirst Corporation (ReliabilityFirst) and the development of consensus for adoption approval revision reaffirmation and deletion of such Standards1 ReliabilityFirst Standards provide for the reliable regional and sub-regional planning and operation of the Bulk Power System2 (BPS) consistent with Good Utility Practice2 within the ReliabilityFirst geographical footprint This procedure was developed under the direction of the ReliabilityFirst Board of Directors (Board) who may request changes to this ReliabilityFirst Reliability Standards Development Procedure (hereinafter referred to as ldquothis Procedurerdquo) as deemed appropriate A procedure for revising this Procedure is contained in Appendix A This Procedure is consistent with the North American Electric Reliability CouncilCorporation (NERC) Reliability Standards Development Procedure Proposed StandardsReliabilityFirst standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA No Standard shall be effective within the ReliabilityFirst area unless filed by NERC with FERC and approved by FERC The approval date of each ReliabilityFirst standard is upon ReliabilityFirst Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 The ReliabilityFirst standard is mandatory and enforceable (with monetary penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint upon approval by FERC The effective date for non-members upon the FERC approval will be determined by the implementation plan that is provided with each new or revised standard

1 Legacy standards such as ECAR Documents MAIN Guides and MAAC Procedures shall be considered ReliabilityFirst Regional Reliability Standards for the purposes of this document until otherwise acted upon by the ReliabilityFirst Board 2 As defined in the ReliabilityFirst By-laws 3 By applying for and becoming a Regular or Associate Member of the Corporation each Member agrees to comply with all Reliability Standards all NERC standards and requirements and the other obligations of Members of the Corporation set forth in the ReliabilityFirst Bylaws or duly adopted by the Board in order to achieve the purposes of the Corporation

Formatted Adjust space between Latin andAsian text Adjust space between Asian textand numbers


Page 2 of 31



ReliabilityFirst Standards shall provide for as much uniformity as possible with NERC reliability standards across the interconnected BPS A ReliabilityFirst Standard shall be more stringent than a NERC reliability standard including a regional difference that addresses matters that the NERC reliability standard does not or shall be a regional difference necessitated by a physical difference in the BPS A ReliabilityFirst Standard that satisfies the statutory and regulatory criteria for approval of proposed NERC reliability standards and that is more stringent than a NERC reliability standard would generally be acceptable ReliabilityFirst Standards when approved by FERC shall be made part of the body of NERC reliability standards and shall be enforced upon all applicable BPS owners operators and users within the ReliabilityFirst area regardless of membership in the region Background Regions may develop through their own processes separate ldquoRegional Standardsrdquo (ReliabilityFirst Standards) that go beyond add detail to or implementaid implementation of NERC reliability standards or otherwise address issues that are not addressed in NERC reliability standards As a condition of ReliabilityFirst membership all ReliabilityFirst Members2 agree to adhere to the NERC reliability standards As such the ReliabilityFirst and its Members will adhere to the NERC reliability standards in addition to the ReliabilityFirst Standards NERC reliability standards and the ReliabilityFirst Standards are both to be included within the ReliabilityFirst Compliance Program







Formatted Outline numbered + Level 1 +Numbering Style Bullet + Aligned at 025 +Tab after 05 + Indent at 05


Page 3 of 31




As contained in the ReliabilityFirst By-laws ReliabilityFirst ldquoRegional Reliability Standardrdquo shall mean a type of Reliability Standard that is applicable only within a particular Regional Entity or group of Regional Entities A Regional Reliability Standard may augment add detail to or implement another Reliability Standard or cover matters not addressed by other Reliability Standards Regional Reliability Standards upon adoption by NERC and approval by the Commission shall be Reliability Standards and shall be enforced within the applicable Regional Entity or Regional Entities pursuant to delegated authorities Inherent in this definition a ReliabilityFirst Standard will define certain obligations or requirements of entities that own operate plan and use the BPS within the ReliabilityFirst geographical footprint These obligations or requirements as contained in the ReliabilityFirst Standards are to be measurable and consistent with Good Utility Practice Standards are not to include processes or procedures that implement a Standard In addition obligations requirements or procedures imposed upon ReliabilityFirst by NERC reliability standards are not to be ReliabilityFirst Standards unless those obligations requirements or procedures require the establishment of a ldquopolicy or standardrdquo as defined by the ReliabilityFirst By-laws Characteristics of a Regional Reliability Standard A Standard is policy or standard including adequacy criteria to provide for the reliable regional and sub-regional planning and operation of the BPS consistent with Good Utility Practice A Standard shall generally have the following characteristics




Format Requirements of a Regional Reliability Standard A Standard shall consist of the format requirements shown in the Regional Reliability Standard Template These requirements apply to the development and revision of Standards These requirements are necessary to achieve Standards that are measurable




Page 4 of 31



enforceable and consistent Supporting documents to aid in the implementation of a Standard may be referenced by the Standard but are not part of the Standard itself The most current version of the approved NERC Reliability Standard template and its associated elements posted on the NERC website will be used at the time of the development of a ReliabilityFirst Regional Reliability Standard if different from the elements listed below








Requirement(s) Explicitly stated technical performance and preparedness requirements Each requirement identifies what entity is responsible and what action is to be performed or what outcome is to be achieved EachCompliance is mandatory for each statement in the requirements section shall be a statement for which compliance is mandatory

Formatted Table


Page 5 of 31



Risk Factor(s)


Measure(s) Each requirement shall be addressed by one or more measurements Measurements that will be used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measurement identifies to whom the measurement applies Each measurement shall be tangible practical and as objective as is practical Achieving the full compliance level of each measurement should beis a necessary and sufficient indicator that the requirement was met



Page 6 of 31






for measuring performance or outcomes bull The process that will be used to evaluate data or information for

the purpose of assessing performance or outcomes bull The entity that is responsible for evaluating data or information to

assess performance or outcomes bull The time period in which performance or outcomes is measured

evaluated and then reset bull Measurement dataData retention requirements and assignment of

responsibility for data archiving bull Violation severity levels

Formatted Indent Left 018 Hanging 013 Outline numbered + Level 1 +Numbering Style Bullet + Aligned at 025 +Tab after 05 + Indent at 05


Page 7 of 31






Each ReliabilityFirst Standard shall have an associated implementation plan describing the effective date of the Standard or effective dates if there is a phased implementation The implementation plan may also describe the implementation of the Standard in the compliance program and other considerations in the initial use of the Standard such as necessary tools training etc The implementation plan must be posted for at least one public comment period and isbe approved as part of the ballot of the standard


This section references related documents that support reasons for or otherwise provide additional information related to the Standard Examples include but are not limited to bull Glossary of Terms bull Developmental history of the Standard and prior versions bull Subcommittee(s) responsible for Standard bull Notes pertaining to implementation or compliance bull Standard references bull ProceduresPractices bull Training andor Technical Reference


Formatted Table

Formatted Indent Left 015 Hanging 013 Outline numbered + Level 1 +Numbering Style Bullet + Aligned at 025 +Tab after 05 + Indent at 05 Tab stops 028 List tab


Page 8 of 31



will advise the ReliabilityFirst Board on Standards presented for adoption by the ReliabilityFirst Board Standards Process Manager (SPM) ndash A person or persons on the ReliabilityFirst staff assigned the task of ensuring that the development revision or deletion of Standards is in accordance with this Procedure The SPM works to ensure the integrity of the process and consistency of quality and completeness of the Standards The SPM facilitates the administration of all actions contained in all steps in the process Standards Process Staff ndash Employees of the ReliabilityFirst that work with or for the SPM Interim Compliance Committee (ICC) ndash The ReliabilityFirst committee responsible for the administration of the ReliabilityFirst Compliance Program The duties of this committee includes but not limited to providing inputs and comments during the standards development process to ensure the measures will be effective and other aspects of the Compliance Program can be practically implemented Standard Drafting Team (SDT) ndash Normally aA team of technical experts and typically includesincluding a member of the ReliabilityFirst Standards staff and the Originator assigned the task of developing a proposed Standard based upon an approved SAR using the Standard development process contained in this Procedure Ballot Body (BB) ndash The Ballot Body comprises all entities that qualify for one or more of the categories and are registered with ReliabilityFirst as potential ballot participants in the voting on standards The categories of registration within the Ballot Body and the registration process are described in Appendix D Ballot Pool ndash The Ballot Pool is comprised of those members of the Ballot Body that register to vote for each particular standard that is up for vote A separate Ballot Pool is established for each standard up for vote Only individuals who have joined the Ballot Pool for that particular standard are eligible to vote on a standard Reliability Committee (RC) ndash The ReliabilityFirst RC serves as a technical advisory body to address the reliability related activities required by the Reliability Standards via review and discussion of the regional activities as requested by the SC Regional Reliability Standard Development Process (Flow chart of Process shown in Appendix C) Assumptions and Prerequisites The ReliabilityFirst Regional Reliability Standards Development Process has the following characteristics


Page 9 of 31




bull Openness - Participation is open to all Organizations who are directly

and materially affected by the ReliabilityFirst region BPS reliability There shall be no undue financial barriers to participation Participation shall not be conditioned upon membership in the ReliabilityFirst and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements Meetings of SDTs are open to the ReliabilityFirst membership and to others









Each standard shall enable or support one or more of the reliability principles thereby ensuring that each standard serves a purpose in support of the reliability of the regional BPS Each standard shall also be consistent with all of the reliability principles thereby ensuring that no standard undermines reliability through an unintended consequence While ReliabilityFirst Standards are intended to promote reliability they must at the same time accommodate competitive electricity markets Reliability is a necessity for electricity markets and robust electricity markets can support reliability Recognizing that BPS reliability and electricity markets are inseparable and mutually interdependent all ReliabilityFirst Standards shall be consistent with NERCrsquos market interface principles Consideration of the market interface principles is intended to ensure that




Page 10 of 31



standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets ReliabilityFirst will coordinate with NERC such that the acknowledgement of receipt of a standard request identified in step 1 notice of comment posting period identified in step 4 and notice for vote identified in step 5 below are concurrently posted on both the ReliabilityFirst and NERC websites Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete a Regional Reliability Standard Any individual representing an organization (Originator) which is directly or materially impacted by the operation of the BPS within the geographical footprint of the ReliabilityFirst may request via a submittal of a Standard Authorization Request (SAR) form the development modification or deletion of a ReliabilityFirst Standard Any such request shall be submitted to the ReliabilityFirst SPM or hisher designee or by another process as otherwise posted on the ReliabilityFirst website The SAR form may be downloaded from the ReliabilityFirst website The SAR contains a description of the proposed Standard subject matter containing sufficiently descriptive detail to clearly define the purpose scope impacted parties and other relevant information of the proposed Standard The SPM will verify that the submitted SAR form has been adequately completed The SPM may offer the Originator suggestions regarding changes andor improvements to improve clarity and assist the ReliabilityFirst community to understand the Originatorrsquos intent and objectives The Originator is free to accept or reject these suggestions Within 15 days the SPM will electronically acknowledge receipt of the SAR The SPM will forward allthe adequately completed SARs complete SAR to the ReliabilityFirst SC Within 60 at which time the SC will post the SAR for comments within 15 days SARs will be posted and publicly noticed Comments on the SARs will be accepted for a 30-day period from the notice of receiptposting Comments will be accepted online using an internet-based application The SPM will provide a copy of an adequately completed SARthe comments to the Originator and the SC Based on the comments the SC shall make available a consideration of comments report and determine the disposition of the SAR (within 60 calendar days following the SAR commenting period) The disposition decision and decision process shall use the normal ldquobusiness rules and proceduresrdquo of the SC then in effect The SC may take one of the following actions3 in accordance with the ReliabilityFirst Standards Committee Governance document



Page 11 of 31









Any SAR that is accepted by the SC for development of a Standard (or modification or deletion of an existing Standard) shall be posted for public viewing on the ReliabilityFirst website within no greater than 30 days of acceptance by the SC The status of posted SARs will be publicly noted at regularly scheduled (appropriately two weeks) intervalsposted Any documentation of the deliberations of the SC concerning SARs shall be made available according to the ldquoReliabilityFirst Standards Committee Governancerdquo document then in effect The SC shall submit a written report to the ReliabilityFirst Board on a periodic basis (at least at every regularly scheduled ReliabilityFirst Board meeting) showing the status of all SARs that have been brought to the SC for consideration Step 2 ndash Formation of the Standard Drafting Team and Declaration of Milestone Date Upon acceptance by the SC of a SAR for development of a new Standard (or modification or deletion of an existing Standard) the SC shall direct the SPM to develop a qualified balance slate for the SDT using the specific directions and preferences of the SC The SPM will send out self-nomination forms to solicit SDT nominees The SDT will consist of a group of people (members of ReliabilityFirst and as appropriate non-members) who collectively have the necessary technical expertise and work process skills The SPM will recommend a slate of ad-hoc individuals or a preexisting task force work group or similar for the SDT based upon the SCrsquos desired SDT capabilities



Formatted List Paragraph Adjust spacebetween Latin and Asian text Adjust spacebetween Asian text and numbers



Page 12 of 31



The SC may also direct the SPM to designate an existing ReliabilityFirst committee (or subset thereof) as the SDT augmented by other persons as may be appropriate for the subject matter The SC will insure that SDT membership includes all necessary administrative support This support typically includes a ReliabilityFirst staff member and the Originator if heshe chooses to participate The SC appoints the interim chair (should not be a staff person) of the SDT The SDT will elect the permanent Chair and Vice-chair at its first meeting The SPM submits the proposed list of names of the SDT to the SC The SC will either accept the recommendations of the SPM or modify the SDT slate as it deems appropriate within 60 days of accepting a SAR for development Upon approval of the SDT slate the SC will declare a preliminary date on which the SDT is expected to have ready a completed draft Standard and associated supporting documentation available for consideration by the ReliabilityFirst membership Step 3 ndash Work and Work Product of the Standard Drafting Team The SDT will then develop a work plan for completing the Standard development work including the establishment of milestones for completing critical elements of the work in sufficient detail to ensure that the SDT will meet the date objectivedeadline established by the SC or the SDT shall propose an alternative date This plan is then delivered to the SC for its concurrence The SDT is to meet either in person or via electronic means as necessary establish sub-work teams (made up of members of the SDT) as necessary and performs other activities to address the parameters of the SAR and the milestone date(s) established by the SC The work product of the SDT will consist of the following







Upon completion of these tasks the SDT submits these documents to the SC which will verify that the proposed Standard is consistent with the SAR on which it was developed



Page 13 of 31



The SDT regularly (at least once each month) informs the SC of its progress in meeting a timely completion of the draft Standard The SDT may request of the SC scope changes of the SAR at any point in the Standard development process The SC may at any time exercise its authority over the Standards development process by directing the SDT to move to Step 4 and post for comment the current work product If there are competing drafts the SC may at its sole discretion have postedpost the version(s) of the draft Standard for comment on the ReliabilityFirst website The SC may take this step at any time after a SDT has been commissioned to develop the Standard Step 4 ndash Comment Posting Period At the direction from the SC the SPM then facilitates the posting of the draft Standard on the ReliabilityFirst website along with a draft implementation plan and supporting documents for a 30-day comment period The SPM shall also inform ReliabilityFirst Members and other potentially interested entities inside or outside of ReliabilityFirst of the posting using typical membership communication procedures then currently in effect or by other means as deemed appropriate As early as the start of the first posting for comment entities may join one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted The Ballot Pool category description and associated requirements are in Appendix D Within 30 days of the conclusion of 30-day comment posting period the SDT shall convene and consider changes to the draft Standard the implementation plan andor supporting technical documents based upon comments received Based upon these comments the SDT may elect to return to step 3 to revise the draft Standard implementation plan andor supporting technical documentation The SDT shall prepare a ldquomodification reportrdquo summarizing the comments received and the changes made as a result of these comments The modification report also summarizes comments that were rejected by the SDT and the reason(s) that these comments were rejected in part or whole Responses to all comments will be posted on the ReliabilityFirst website no later than the next posting of the proposed Standard Step 5 ndash Posting for Voting by ReliabilityFirst Registered Ballot Body Upon recommendation of the SDT and if the SC concurs that all of the requirements for development of the Standard have been met the SPM will post the revised draft Standard implementation plan supporting technical documentation and the ldquomodification reportrdquo Once the notice for a vote has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued


Page 14 of 31



Entities may register in the BB at any time during the Standards process The BB category description and associated rules are in Appendix D By 1159 PM Central Prevailing Time (CPT) of the seventh day of the 15 day pre -ballot posting period registered BB entitiesmembers intending to vote on the proposed standard must have joined one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted The SPM will schedule a Vote by the Ballot Pool which is to be scheduled to commence no sooner than 15 days and no later than 30 days following this posting The Vote by the Ballot Pool is an advisory to the ReliabilityFirst Board The Ballot Pool shall be allowed to vote over a period of 15 days It is expected that votesVotes will be submitted electronically but may be submitted through other means as approved by the SC All entities registered as part of the BB members are eligible to participate in voting on proposed new Standards Standard revisions or Standard deletions There is a requirement to separately join a Ballot Pool to participate in voting for each standard Each entity can join only in one category of the Ballot Pool and shall have one vote The voting results will be composed of only the votes from BB entities that have joined the Ballot Pool for the standard being voted on and responding within the 15 day voting period Votes may be accompanied by comments explaining the vote but are not required All comments shall be responded to and posted to the ReliabilityFirst website prior to going to the SC or Board Step 6A ndash Voting Receives SimpleTwo-Thirds or Greater Majority of Affirmative Category Votes A simpletwo-thirds or greater majority45 of votes within a category determines the vote for that category If The Initial ballot has passed if there is a simpletwo-thirds or greater affirmative majority of category votes (only those categories with votes cast will be considered) during the 15-day voting period and a quorum is met (a quorum consists of a simple majority of individuals who have joined the Ballot Pool) the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7)6 is met If there is at least one (1) Negative vote with comment during the initial ballot then the standard will be posted for a 10-day Recirculation ballot If there are no Negative votes with comments the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7) In the recirculation ballot members of the Ballot Pool shall again be presented the proposed standard (that has not been significantly changed from the previous ballot) along with the reasons for negative votes the responses and any resolution of the differences An insignificant revision is a revision that does not change the scope 4 For the purposes of determining majority within a category an abstention is not considered a vote 5 For the purposes of determining majority within a category an abstention is not considered a vote 6 A quorum is achieved when three-fourths (75) or greater of the ballot pool casts a vote

Formatted Font Not Italic

Formatted Font Italic



Page 15 of 31



applicability or intent of any requirement and includes but is not limited to things such as correcting the numbering of a requirement correcting the spelling of a word adding an obviously missing word or rephrasing a requirement for improved clarity Where there is a question as to whether a proposed modification is ldquosubstantiverdquo the Standards Committee shall make the final determination All members of the Ballot Pool shall be permitted to reconsider and change their vote from the prior ballot Members of the Ballot Pool who did not respond to the prior ballot shall be permitted to vote in the recirculation ballot In the recirculation ballot Ballot Pool members may indicate a revision to their original vote otherwise their vote shall remain the same as in their prior ballot Upon successful completion of the initial and recirculation voting periods the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7) Step 6B ndash Voting Does Not Receive SimpleTwo-Thirds or Greater Majority of Affirmative Category Votes or a QuorumQuorum5 is Not Met If a draft Standard does not receive a simpletwo-thirds or greater affirmative majority of votes determined for each category (only those categories with votes cast will be considered) or does not reach quorum during the 15-day voting period or a quorum is not met during the 15-dayInitial voting period the SC may


bull Direct the existing SDT to reconsider or modify certain aspects of the draft


o If there is a simpletwo-thirds or greater affirmative majority of categories

with votes cast and a quorum is met during the second voting periodinitial ballot and second recirculation ballot the SC will forward it to the ReliabilityFirst Board for action (Step 7)

o If a draft Standard does not receive a simpletwo-thirds or greater majority

of affirmative category votes cast during the second voting periodinitial ballot or a quorum is not met the SC will refer the draft Standard and implementation plan to the ReliabilityFirst Board The SC may also submit an assessment opinion and recommendations to the ReliabilityFirst Board (Step 7)


Formatted Indent Left 025

Formatted Bulleted + Level 1 + Aligned at 025 + Tab after 025 + Indent at 05


Page 16 of 31



bull Revise the SAR on which the draft Standard was based and remand the development work back to the original SDT or a newly appointed SDT The resulting draft Standard andor implementation plan will be posted for a second voting period The SC may require a second comment period prior to a second voting period The second posting of the draft Standard implementation plan and supporting documentation shall be within 60 days of the SC action


with votes cast during the second voting period and a quorum is met during the second initial ballot and second recirculation ballot the SC will forward it to the ReliabilityFirst Board for action (Step 7)


of affirmative category votes cast during the second voting period or a quorum is not met the SC will refer the draft Standard and implementation plan to the ReliabilityFirst Board The SC may also submit an assessment opinion and recommendations to the ReliabilityFirst Board (Step 7)


under consideration and so notify the ReliabilityFirst Board Step 7 ndash Action by the ReliabilityFirst Board A draft Standard submitted to the ReliabilityFirst Board for action must be publicly posted at least 30 days prior to action by the Board At a regular or special meeting the ReliabilityFirst Board shall consider adoption of the draft Standard The Board will consider the results of the voting and dissenting opinions The Board will consider any advice offered by the SC Draft Standards that received a simple affirmative majoritytwo-thirds or greater of categories with votes cast shall be delivered to the ReliabilityFirst Board for their action The ReliabilityFirst Board shall be provided with an ldquoinformational packagerdquo which includes








Page 17 of 31





Draft Standards that did not receive a simple affirmative majoritytwo-thirds or greater of categories with votes cast in the second voting period shall be delivered to the ReliabilityFirst Board for their action The ReliabilityFirst Board shall be provided with an ldquoinformational packagerdquo




Once a regional ReliabilityFirst Standard is approved by the Board the standard will be submitted to NERC for approval and filing with FERC Step 8 - Implementation of a Regional Reliability Standard Upon approval of a draft Standard action by FERC theThe SPM will notify the membership upon ReliabilityFirst Board approval of the effective datestandard through the normal and customary membership communication procedures and processes then in effect The SPM will also notify the ReliabilityFirst Compliance Staff for integration into the ReliabilityFirst Compliance Program The approval date of each ReliabilityFirst standard is upon Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 ReliabilityFirst standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA Upon approval of a ReliabilityFirst standard action by FERC it is mandatory and enforceable (with monetary







Page 18 of 31



penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint The effective date for non-members upon the FERC approval will be determined by the implementation plan that is provided with each new or revised standard


Page 19 of 31



Appendix A Maintenance of Regional Reliability Standards Development Process Significant changes to this Procedure shall begin with the preparation of a SAR and be handled using the same procedure as a request to add modify or delete a Standard The ReliabilityFirst SC has the authority to make lsquominorrsquo changes to this Procedure as deemed appropriate by the SC and subject to the SC voting practices and procedures according to the ldquoReliabilityFirst Standards Committee Governancerdquo document then in effect The SC shall promptly notify the ReliabilityFirst Board of such lsquominorrsquo changes to this Procedure for their review and concurrence at the next ReliabilityFirst Board meeting Maintenance of Regional Reliability Standards The SC shall ensure that each Standard shall be reviewed at least once every five years from the effective date of the Standard or the latest revision to the Standard whichever is the later The review process shall be conducted by soliciting comments from the stakeholders If no changes are warranted the SC shall recommend to the ReliabilityFirst Board that the Standard be reaffirmed If the review indicates a need to revise or delete a Standard a SAR shall be prepared and submitted in accordance with the standards development process contained in this Procedure Urgent Action Under certain conditions the SC may designate a proposed Standard or revision to a Standard as requiring urgent action Urgent action may be appropriate when a delay in implementing a proposed Standard or revision could materially impact reliability of the BPS The SC must use its judgment carefully to ensure an urgent action is truly necessary and not simply an expedient way to change or implement a Standard A requester prepares a SAR and a draft of the proposed Standard and submits both to the SPM The SAR must include a justification for urgent action The SPM submits the request to the SC for its consideration If the SC designates the requested Standard or revision as an urgent action item then the SPM shall immediately post the draft for pre-ballot review This posting requires a minimum 30-day posting period before the ballot and applies the same voting procedure as detailed in Step 5 Processing will continue as outlined in the subsequent steps In the event additional drafting is required a SDT will be assembled as outlined in the Procedure Any Standard approved as an urgent action shall have a termination date specified that shall not exceed one year from the approval date Should there be a need to make the Standard permanent then the Standard would be required to go through the full Standard


Page 20 of 31



development process All urgent action Standards require ReliabilityFirst Board NERC and FERC approval as outlined for Standards in the regular process Urgent actions that expire may be renewed using the urgent action process again in the event a permanent Standard is not adopted In determining whether to authorize an urgent action Standard for a renewal ballot the SC shall consider the impact of the Standard on the reliability of the BPS and whether expeditious progress is being made toward a permanent replacement Standard The SC shall not authorize a renewal ballot if there is insufficient progress toward adopting a permanent replacement Standard or if the SC lacks confidence that a reasonable completion date is achievable The intent is to ensure that an urgent action Standard does not in effect take on a degree of permanence due to the lack of an expeditious effort to develop a permanent replacement Standard With these principles there is no predetermined limit on the number of times an urgent action may be renewed However each urgent action Standard renewal shall be effective only upon approval by the ReliabilityFirst Board NERC and FERC Any person or entity including the SDT working on a permanent replacement Standard may at any time submit a SAR proposing that an urgent action Standard become a permanent Standard by following the full Standards process Interpretations of Standards All persons who are directly and materially affected by the reliability of ReliabilityFirst BPS shall be permitted to request an interpretation of the standard The person requesting an interpretation will send a request to the SPM explaining the specific circumstances surrounding the request and what clarifications are required as applied to those circumstances The request should indicate the material impact to the requesting party or others caused by the lack of clarity or a possibly incorrect interpretation of the standard The SPM along with guidance from the SC will assemble a team with the relevant expertise to address the request The Interpretation Drafting Team (IDT) typically consists of members from the original SDT The SPM submits the proposed list of names of the IDT to the SC The SC will either accept the recommendations of the SPM or modify the IDT slate As soon as practical (not more than 45 days) the team will prepare an initial draft a written interpretation toof the standard addressing the issues raised Once the IDT has completed athe initial draft interpretation to the Standard addressing only the issues raised the team will post the draft for a 30-day informal7 stakeholder comment period The IDT will review the stakeholder feedback and may make changes before preparing a final draft of the interpretation The IDT will then forward the draft interpretation to the 7 An informal comment period does not require the IDT to respond to every stakeholder comment and is only used to make potential changes for the final draft of the interpretation


Page 21 of 31



SPM The SPM will forward the draft interpretation to the Interim Compliance Committee (ICC)The ICC is to assess if the inclusion of the interpretation lessens the measurability of the Standard In addition the The SPM will forward the interpretation to the Reliability Committee (RC) Barring receipt of an opinion from either the ICC or RC within 21 calendar days that the interpretation sufficiently lessens measurability or is not technically appropriate for the Standard respectively the SPM will forward the interpretation to the SC The SC will determine if the interpretation is consistent with the Standard and does not add additional requirements to the standard The SC will forward the interpretation to the ReliabilityFirst Board for informational purposes as being appended to the approved Standard Note In the event that the ICCRC determines that measurability is lessened the ICCinterpretation makes the standard technically inappropriate the RC shall provide an explanation of its reasoning to the SPM and IDT for inclusion in a subsequent revision The RC shall in a similar manner provide an explanation of its reasoning if it determines that the interpretation makes the standard technically inappropriate In either case the IDT and SPM will continue to re-circulate the interpretation as stated above The interpretation will stand until such time as the standard is revised through the normal process at which time the standard will be modified to incorporate the clarifications provided by the interpretation Appeals Persons who have directly and materially affected interests and who have been or will be adversely affected by any substantive or procedural action or inaction related to the development approval revision reaffirmation or withdrawal of a Standard shall have the right to appeal This appeals process applies only to the Standards process as defined in this Procedure The burden of proof to show adverse effect shall be on the appellant Appeals shall be made within 30 days of the date of the action purported to cause the adverse effect except appeals for inaction which may be made at any time In all cases the request for appeal must be made prior to the next step in the process The final decisions of any appeal shall be documented in writing and made public The appeals process provideshas two levels with the goal of expeditiously resolving the issue to the satisfaction of the participants Level 1 Appeal Level 1 is the required first step in the appeals process The appellant submits a complaint in writing to the SPM that describes the substantive or procedural action or inaction associated with a Standard or the standards process The appellant describes in the complaint the actual or potential adverse impact to the appellant Assisted by any


Page 22 of 31



necessary staff and committee resources the SPM shall prepare a written response addressed to the appellant as soon as practical but not more than 45-days after receipt of the complaint If the appellant accepts the response as a satisfactory resolution of the issue both the complaint and response will be made a part of the public record associated with the standard Level 2 Appeal If after the Level 1 Appeal the appellant remains unsatisfied with the resolution as indicated by the appellant in writing to the SPM the SPM shall convene a Level 2 Appeals Panel This panel shall consist of five members total appointed by the ReliabilityFirst Board In all cases Level 2 Appeals Panel members shall have no direct affiliation with the participants in the appeal The SPM shall post the complaint and other relevant materials and provide at least 30-days notice of the meeting of the Level 2 Appeals Panel In addition to the appellant any person that is directly and materially affected by the substantive or procedural action or inaction referenced in the complaint shall be heard by the panel The panel shall not consider any expansion of the scope of the appeal that was not presented in the Level 1 Appeal The panel may in its decision find for the appellant and remand the issue to the SC with a statement of the issues and facts in regard to which fair and equitable action was not taken The panel may find against the appellant with a specific statement of the facts that demonstrate fair and equitable treatment of the appellant and the appellantrsquos objections The panel may not however revise approve disapprove or adopt a reliability standard The actions of the Level 2 Appeals Panel shall be publicly posted In addition to the foregoing a procedural objection that has not been resolved may be submitted to the ReliabilityFirst Board for consideration at the time the Board decides whether to adopt a particular reliability standard The objection must be in writing signed by an officer of the objecting entity and contain a concise statement of the relief requested and a clear demonstration of the facts that justify that relief The objection must be filed no later than 30-days after the announcement of the vote on the Standard in question


Page 23 of 31








Company

New Standard







Request Date

ID




Page 24 of 31



















Page 25 of 31



















Page 26 of 31





yes or no


yes or no


yes or no


yes or no



Page 27 of 31





Page 28 of 31





Related SARs



Page 29 of 31






on (date)




Page 30 of 31




Step 1

SC Action

Remand SAR

Accept SAR

Reject SAR

Post Request for

SDT Step 2

Appoint SDT








to SPM


Page 31 of 31



Category Vote

SC Action

Board Action

Revise Standard


Direct SDT to Modify

SC Assessment

File for Approval and Implement

Standard

2nd Category Vote

Majority Affirmative


Yes No

Yes

No

SC Forwards to BOD

Step 5

Step 6B Step 6A

Step 7

Step 8


Page 32 of 31



Step 1

SC Action

Remand SAR

Accept SAR

Reject SAR

Post Request for

SDT

Step 2

Appoint SDT










to SPM


Page 33 of 31




SC Action

Revise SAR



SC Assessment



2nd Category Vote


Affirmative


Affirmative

Yes No

Yes

No


Step 5 Step 6B

Step 6A

Step 7

Step 8


No


Yes


Affirmative Yes

A

A


companies

No

B

B

Board Approval

Yes

No

A


Page 34 of 31



Appendix D Ballot Pool Categories For the purposes of category Ballot Pool registration and voting ana person or entity shall register in only one of may join the following categories for each standard that will be voted on (only oneregistered Ballot Pool to vote is allowed peron standards whether or not such person or entity per vote)is a member of ReliabilityFirst A corporation or other organization with integrated operations or with affiliates that qualifies to belong to more than one category (eg Transmission Owners and Load Serving Entities) may join and vote once in each category for which it qualifies provided that each category constitutes a separate membership in the Ballot Body and the organization is represented in each category by a different representative Affiliated entities are collectively limited to one membership in each category in the Ballot Pool for which they are qualified Category 1 ndash Transmission Owner Transmission Operator Transmission Service



Category 5 ndash Distribution Provider Ballot Body Registration Entities may register in the BB at any time during the Standards process The SPM shall review all applications for joining the BB and make a determination of whether they qualify for the self-selection category(ies) In order to comment or vote you must have an active membership in the BB When you submit your registration request to join the BB you are placed in a ldquopending stagerdquo until your account is activated Activation of your account may take up to 24 hours You will be unable to submit comments or join a Ballot Pool until your account is activated The contact designated as primary representative to ReliabilityFirst is the voting member with the secondary contact as the backup Note Registration for a BB is not the same as registration for the compliance registry Although the terminology used to describe the BB categories in most cases has the same

Formatted Underline



Page 35 of 31



meaning as the terms used in the NERC Functional Model registration in a BB goes beyond the compliance registry in that entities smaller than those stated in the compliance registry guidelines are allowed to register in a BB Entities shall have evidence that they qualify for the BB category they register in Such evidence shall be available for the SPM review to verify BB registration and may include compliance registration Ballot Pool Formation In order to participate in voting on a particular standard an entity must join the Ballot Pool being established for the standard as follows 1 ndash As early as the start of the first posting for comment entities may join one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted 2 - By close of business of the seventh day of the 15 day pre ballot posting period entities wishing to vote must have joined one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted Formatted Tab stops 134 Left

Attachment C Exhibit C to ReliabilityFirst Regional Delegation Agreement

(Redline)

Amended and Restated Pro Forma Regional Delegation Agreement Page 1 of 20

Exhibit C ndash Regional Standard Development Procedure Exhibit C shall set forth the Regional Entityrsquos standards development procedure which NERC agrees meets the following common attributes COMMON ATTRIBUTE 1 Proposed regional reliability standards shall be subject to approval by NERC as the electric reliability organization and by FERC before becoming mandatory and enforceable under Section 215 of the FPA [add reference to any applicable authorities in Canada and Mexico] No regional reliability standard shall be effective within the [Regional Entity Name] area unless filed by NERC with FERC [and applicable authorities in Canada and Mexico] and approved by FERC [and applicable authorities in Canada and Mexico] ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Corporation Reliability Standards Development Procedure (ReliabilityFirst Procedure) Introduction 3rd para (Page 1)

ReliabilityFirst standardsProposed Standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA The approval date of each ReliabilityFirst standard is upon ReliabilityFirst Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 The ReliabilityFirst standard is mandatory and enforceable (with monetary penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint upon approval by FERC The effective date for non-members upon FERC approval will be determined by the implementation plan that is provided with each new or revised standardNo Standard shall be effective within the ReliabilityFirst area unless filed by NERC with FERC and approved by FERC

COMMON ATTRIBUTE 2 [Regional Entity Name] regional reliability standards shall provide for as much uniformity as possible with reliability standards across the interconnected bulk power system of the North American continent A [Regional Entity Name] reliability standard shall be more stringent than a continent-wide reliability standard including a regional difference that addresses matters that the continent-wide reliability standard does not or shall be a regional difference necessitated by a physical difference in the bulk power system A regional reliability standard that satisfies the statutory and regulatory criteria for approval of proposed North American reliability standards and that is more stringent than a continent-wide reliability standard would generally be acceptable

Formatted Superscript


ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Introduction 4th para (Page 1) ReliabilityFirst Standards shall provide for as much uniformity as possible with NERC reliability standards across the interconnected BPS A ReliabilityFirst Standard shall be more stringent than a NERC reliability standard including a regional difference that addresses matters that the NERC reliability standard does not or shall be a regional difference necessitated by a physical difference in the BPS A ReliabilityFirst Standard that satisfies the statutory and regulatory criteria for approval of proposed NERC reliability standards and that is more stringent than a NERC reliability standard would generally be acceptable

COMMON ATTRIBUTE 3 [Regional Entity Name] regional reliability standards when approved by FERC [add applicable authorities in Canada] shall be made part of the body of NERC reliability standards and shall be enforced upon all applicable bulk power system owners operators and users within the [Regional Entity Name] area regardless of membership in the region ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Introduction 5th para (Page 21)

ReliabilityFirst Standards when approved by FERC shall be made part of the body of NERC reliability standards and shall be enforced upon all applicable BPS owners operators and users within the ReliabilityFirst area regardless of membership in the region

COMMON ATTRIBUTE 4 Requester ⎯ The requester is the sponsor of the regional reliability standard request and may assist in the development of the standard Any member of [Regional Entity Name] or group within [Regional Entity Name] shall be allowed to request that a regional reliability standard be developed modified or withdrawn Additionally any entity (person organization company government agency individual etc) that is directly and materially affected by the reliability of the bulk power system in the [Regional Entity Name] area shall be allowed to request a regional reliability standard be developed modified or withdrawn ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute




See ReliabilityFirst Procedure Roles in the Organizational Standards Development Process Process Roles 1st para - Originator (Page 7)

Originator - Any entity (person organization company government agency individual etc) that is directly and materially affected by the reliability of the ReliabilityFirst BPS is allowed to request a Standard be developed or an existing Standard is modified or deleted by creating a Standards Authorization Request (SAR) See Appendix B

COMMON ATTRIBUTE 5 [Standards or other named] committee ⎯ The [Regional Entity Name] [standards] committee manages the standards development process The [standards] committee will consider which requests for new or revised standards shall be assigned for development (or existing standards considered for deletion) The [standards] committee will advise the [Regional Entity Name] board on standards presented for adoption ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Roles in the Organizational Standards Development Process Process Roles 3rd para - Standards Committee (Page 7) Standards Committee (SC) - The ReliabilityFirst SC will consider which requests for new or revised Standards shall be assigned for development (or existing Standards considered for deletion) The SC manages the Standards development process The SC will advise the ReliabilityFirst Board on Standards presented for adoption by the ReliabilityFirst Board

COMMON ATTRIBUTE 6 [Alternative 6A For a Regional Entity that chooses to vote using a balanced stakeholder committee] The [standards] committee is a balanced stakeholder committee inclusive of all stakeholder interests that provide for or are materially impacted by the reliability of the bulk power system [The [standards] committee votes to approve standards] See Appendix A for the representation model of the [standards] committee ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

ReliabilityFirst did not choose this option ReliabilityFirst chose option 17B 18B and 19B




[Alternative 6B For a Regional Entity that chooses to vote using a balanced ballot body of stakeholders] [Registered ballot body ⎯ The registered ballot body comprises all entities or individuals that qualify for one of the stakeholder segments are registered with [Regional Entity Name] as potential ballot participants in the voting on standards and are current with any designated fees Each member of the registered ballot body is eligible to vote on standards [Each standard action has its own ballot pool formed of interested members of the registered ballot body Each ballot pool comprises those members of the registered ballot body that respond to a pre-ballot survey for that particular standard action indicating their desire to participate in such a ballot pool] The representation model of the registered ballot body is provided in Appendix A] ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Roles in the Regional Reliability Standards Development Process 5th amp 6th para (Page 8) Ballot Body (BB) ndash The Ballot Body comprises all entities that qualify for one or more of the categories and are registered with ReliabilityFirst as potential ballot participants in the voting on standards The categories of registration within the Ballot Body and the registration process are described in Appendix D Ballot Pool ndash The Ballot Pool is comprised of those members of the Ballot Body that register to vote for each particular standard that is up for vote A separate Ballot Pool is established for each standard up for vote Only individuals who have joined the Ballot Pool for that particular standard are eligible to vote on a standard

COMMON ATTRIBUTE 7 [Regional Entity Name] will coordinate with NERC such that the acknowledgement of receipt of a standard request identified in step 1 notice of comment posting period identified in step 4 and notice for vote identified in step 5 below are concurrently posted on both the [Regional Entity Name] and NERC websites ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 9th para (Page 910)

ReliabilityFirst will coordinate with NERC such that the acknowledgement of receipt of a standard request identified in step 1 notice of comment posting period identified in step 4 and notice for vote identified in step 5 below are concurrently posted on both the ReliabilityFirst and NERC websites


COMMON ATTRIBUTE 8 An acceptable standard request shall contain a description of the proposed regional reliability standard subject matter containing sufficiently descriptive detail to clearly define the purpose scope impacted parties and other relevant information of the proposed standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete an Organizational Standard 2nd para (Page 10)

The SAR contains a description of the proposed Standard subject matter containing sufficiently descriptive detail to clearly define the purpose scope impacted parties and other relevant information of the proposed Standard The SPM will verify that the submitted SAR form has been adequately completed The SPM may offer the Originator suggestions regarding changes andor improvements to improve clarity and assist the ReliabilityFirst community to understand the Originatorrsquos intent and objectives The Originator is free to accept or reject these suggestions Within 15 days the SPM will electronically acknowledge receipt of the SAR

COMMON ATTRIBUTE 9 Within [no greater than 60] days of receipt of a completed standard request the [standards] committee shall determine the disposition of the standard request ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


See ReliabilityFirst Procedure Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete an Organizational Standard 3rd 4th and 5th para (Page 10)

The SPM will forward theall adequately completed SAR s to the ReliabilityFirst SC at which time the SC will post the SAR for comments within 15 days SARs will be posted and publicly noticed Comments on the SARs will be accepted for a 30-day period from the notice of posting Comments will be accepted online using an internet-based application The SPM will provide a copy of the comments to the Originator and the SC Based on the comments the SC shall make available a consideration of comments report and determine the disposition of the SAR (within 60 calendar days following the SAR commenting period) The disposition decision and decision process shall use the normal ldquobusiness rules and proceduresrdquo of the SC then in effect The SC may take one of the following actions in accordance with the ReliabilityFirst Standards Committee Governance document Within 60 days of receipt of an adequately completed SAR the SC shall determine the disposition of the SAR The disposition decision and decision process shall use the normal ldquobusiness rules and proceduresrdquo of the SC then in effect The SC may take one of the following actions

COMMON ATTRIBUTE 10 The [standards] committee may take one of the following actions

bull Accept the standard request as a candidate for development of a new standard revision of an existing standard or deletion of an existing standard The [standards] committee may at its discretion expand or narrow the scope of the standard request under consideration The [standards] committee shall prioritize the development of standard in relation to other proposed standards as may be required based on the volume of requests and resources

bull Reject the standard request If the [standards] committee rejects a standard request a written explanation for rejection will be delivered to the requester within [no greater than 30] days of the decision

bull Remand the standard request back to the requester for additional work The standards process manager will make reasonable efforts to assist the requester in addressing the deficiencies identified by the [standards] committee The requester may then resubmit the modified standard request using the process above The requester may choose to withdraw the standard request from further consideration prior to acceptance by the [standards] committee


Formatted Font 12 pt Superscript




See ReliabilityFirst Procedure Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete an Organizational Standard 6th 7th 8th and 9th para (Page 10 and 110)

bull Accept the SAR as a candidate for development of a new Standard revision of

an existing Standard or deletion of an existing Standard The SC may in its sole discretion expand or narrow the scope of the SAR under consideration The SC shall prioritize the development of SARs as may be required based on the number of SARs under development at any time

bull Reject the SAR If the SC rejects a SAR a written explanation for rejection will be delivered to the Originator within 30 days of the decision


bull Remand the SAR back to the Originator for additional work The SPM will make reasonable efforts to assist the Originator in addressing the deficiencies identified by the SC The Originator may then resubmit the modified SAR using the process above The Originator may choose to withdraw the SAR from further consideration prior to re-submittal to the SC

COMMON ATTRIBUTE 11 Any standard request that is accepted by the [standards] committee for development of a standard (or modification or deletion of an existing standard) shall be posted for public viewing on the [Regional Entity Name] website within [no greater than 30] days of acceptance by the committee ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete an Organizational Standard 3rd5th para (Page 110)

Any SAR that is accepted by the SC for development of a Standard (or modification or deletion of an existing Standard) shall be posted for public viewing on the ReliabilityFirst website within no greater than 30 days of acceptance by the SC The status of posted SARs will be publicly posted noted at regularly scheduled (appropriately two weeks) intervals

COMMON ATTRIBUTE 12






The standards process manager shall submit the proposed members of the drafting team to the [standards] committee The [standards] committee shall approve the drafting team membership within 60 days of accepting a standard request for development modifying the recommendations of the standards process manager as the committee deems appropriate and assign development of the proposed standard to the drafting team ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 2 ndash Formation of the Standard Drafting Team and Declaration of Milestone Date 1st3rd para (Page 121)

The SPM submits the proposed list of names of the SDT to the SC The SC will either accept the recommendations of the SPM or modify the SDT slate as it deems appropriate within 60 days of accepting a SAR for development

COMMON ATTRIBUTE 13 At the direction from the [standards] committee the standards process manager shall facilitate the posting of the draft standard on the [Regional Entity Name] website along with a draft implementation plan and supporting documents for a no less than a [30]-day comment period The standards process manager shall provide notice to [Regional Entity Name] stakeholders and other potentially interested entities both within and outside of the [Regional Entity Name] area of the posting using communication procedures then currently in effect or by other means as deemed appropriate ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 4 ndash Comment Posting Period 1st para (Page 132)

At the direction from the SC the SPM then facilitates the posting of the draft Standard on the ReliabilityFirst website along with a draft implementation plan and supporting documents for a 30-day comment period The SPM shall also inform ReliabilityFirst Members and other potentially interested entities inside or outside of ReliabilityFirst of the posting using typical membership communication procedures then currently in effect or by other means as deemed appropriate As early as the start of the first posting for comment entities may join one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted The Ballot Pool category description and associated requirements are in Appendix D




The drafting team shall prepare a summary of the comments received and the changes made to the proposed standard as a result of these comments The drafting team shall summarize comments that were rejected by the drafting team and the reason(s) that these comments were rejected in part or whole The summary along with a response to each comment received will be posted on the [Regional Entity Name] website no later than the next posting of the proposed standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 4 ndash Comment Posting Period 3rd para (Page 13) The SDT shall prepare a ldquomodification reportrdquo summarizing the comments received and the changes made as a result of these comments The modification report also summarizes comments that were rejected by the SDT and the reason(s) that these comments were rejected in part or whole Responses to all comments will be posted on the ReliabilityFirst website no later than the next posting of the proposed Standard

COMMON ATTRIBUTE 15 Upon recommendation of the drafting team and if the [standards] committee concurs that all of the requirements for development of the standard have been met the standards process manager shall post the proposed standard and implementation plan for ballot and shall announce the vote to approve the standard including when the vote will be conducted and the method for voting Once the notice for a vote has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 5 ndash Posting for Voting by ReliabilityFirst Membership 1st para (Page 13) Upon recommendation of the SDT and if the SC concurs that all of the requirements for development of the Standard have been met the SPM will post the revised draft Standard implementation plan supporting technical documentation and the ldquomodification reportrdquo Once the notice for a vote has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued





The standards process manager shall schedule a vote by the [Regional Entity Name] [registered ballot body[standards] committee] The vote shall commence no sooner than [15] days and no later than [30] days following the issuance of the notice for the vote ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 5 ndash Posting for Voting by ReliabilityFirst Membership 3rd para (Page 13)

By 1159 PM Central Prevailing Time (CPT) of the seventh day of the 15 day pre- ballot posting period registered BB membersentities intending to vote on the proposed standard must have joined one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted The SPM will schedule a Vote by the Ballot Pool which is to be scheduled to commence no sooner than 15 days and no later than 30 days following this posting The Vote by the Ballot Pool is an advisory to the ReliabilityFirst Board

COMMON ATTRIBUTE 17 [Alternative 17A For an RE that chooses to vote using a balanced stakeholder committee] The [standards] committee shall give due consideration to the work of the drafting team as well as the comments of stakeholders and minority objections in approving a proposed regional reliability standard for submittal to the [Regional Entity Name] board The [standards] committee may vote to approve or not approve the standard Alternatively the [standards] committee may remand the standard to the drafting team for further work or form a new drafting team for that purpose ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute ReliabilityFirst did not choose this option ReliabilityFirst chose option 17B 18B and 19B [Alternative 17B For an RE that chooses to vote using a balanced ballot body of stakeholders] The [Regional Entity Name] registered ballot body shall be able to vote on the proposed standard during a period of [not less than 10] days ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 5 ndash Posting for Voting by ReliabilityFirst Membership 4th para (Page 143)



The Ballot Pool shall be allowed to vote over a period of 15 days It is expected that vVotes will be submitted electronically but may be submitted through other means as approved by the SC

COMMON ATTRIBUTE 18 [Alternative 18A For an RE that chooses to vote using a balanced stakeholder committee] The [standards] committee may not itself modify the standard without issuing a new notice to stakeholders regarding a vote of the modified standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

ReliabilityFirst did not choose this option ReliabilityFirst chose option 17B 18B and 19B [Alternative 18B For an RE that chooses to vote using a balanced ballot body of stakeholders] All members of [Regional Entity Name] are eligible to participate in voting on proposed new standards standard revisions or standard deletions [Alternatively Each standard action requires formation of a ballot pool of interested members of the registered ballot body] ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


All entities registered as part of the BB members are eligible to participate in voting on proposed new Standards Standard revisions or Standard deletions There is a requirement to separately join a Ballot Pool to participate in voting for each standard Each entity can join only in one category of the Ballot Pool and shall have one vote The voting results will be composed of only the votes from BB entities that have joined the Ballot Pool for the standard being voted on and responding within the 15 day voting period Votes may be accompanied by comments explaining the vote but are not required All comments shall be responded to and posted to the ReliabilityFirst website prior to going to the SC or Board

COMMON ATTRIBUTE 19 [Alternative 19A For an RE that chooses to vote using a balanced stakeholder committee]


Formatted Font 12 pt Not Italic


Actions by the committee shall be recorded in the regular minutes of the committee ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

ReliabilityFirst did not choose this option ReliabilityFirst chose option 17B 18B and 19B [Alternative 19B For an RE that chooses to vote using a balanced ballot body of stakeholders] Approval of the proposed regional reliability standard shall require a [two thirds] majority in the affirmative (affirmative votes divided by the sum of affirmative and negative votes) Abstentions and non-responses shall not count toward the results except that abstentions may be used in the determination of a quorum A quorum shall mean [XX] of the members of the [registered ballot bodyballot pool] submitted a ballot ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 6A ndash Membership Voting Receives Two-Thirds or GreaterSimple Majority of Affirmative Category Votes 1st para (Page 14) A two-thirds or greater simple majority1 of votes within a category determines the vote for that category The Initial ballot has passed ifIf there is a two-thirds or greatersimple affirmative majority of category votes (only those categories with votes cast will be considered) during the 15-day voting period and a quorum2 is met (a quorum consists of a simple majority of individuals who have joined the Ballot Pool) the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7)

COMMON ATTRIBUTE 20 Under no circumstances may the board substantively modify the proposed regional reliability standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute




See ReliabilityFirst Procedure Step 7 ndash Action by the ReliabilityFirst Board of Directors5th 3rd para (Page 165)

bull Approve the draft Standard action with only minor or no modification Under

no circumstances may the Board substantively modify the proposed regional reliability standard

COMMON ATTRIBUTE 21 Once a regional reliability standard is approved by the board the standard will be submitted to NERC for approval and filing with FERC [and applicable authorities in Canada and Mexico] ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 7 ndash Action by the ReliabilityFirst Board of Directors 6th5th para (Page 176) Once a regional ReliabilityFirst Standard is approved by the Board the standard will be submitted to NERC for approval and filing with FERC


bull Open - Participation in the development of a regional reliability standard shall be open to all organizations that are directly and materially affected by the [Regional Entity Name] bulk power system reliability There shall be no undue financial barriers to participation Participation shall not be conditioned upon membership in [Regional Entity Name] and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements Meetings of drafting teams shall be open to the [Regional Entity Name] members and others


See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 3rdd para - Openness (Page 9)

Openness - Participation is open to all Organizations who are directly and materially affected by the ReliabilityFirst region BPS reliability There shall be no undue financial barriers to participation Participation shall not be conditioned upon membership in the ReliabilityFirst and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements Meetings of SDTs are open to the ReliabilityFirst membership and to others






bull Balanced - The [Regional Entity Name] standards development process strives to have an appropriate balance of interests and shall not be dominated by any two interest categories and no single interest category shall be able to defeat a matter


See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 4th para - Balance (Page 9)

Balanced - The ReliabilityFirst standards development process strives to have an appropriate balance of interests and shall not be dominated by any two interest categories and no single interest category shall be able to defeat a matter


bull Inclusive mdash Any entity (person organization company government agency individual etc) with a direct and material interest in the bulk power system in the [Regional Entity Name] area shall have a right to participate by a) expressing a position and its basis b) having that position considered and c) having the right to appeal


See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 5th para - Inclusive (Page 9)

Inclusive - Any entity (person organization company government agency individual etc) with a direct and material interest in the BPS in the ReliabilityFirst area shall have a right to participate by a) expressing a position and its basis b) having that position considered and c) having the right to appeal


bull Fair due process mdash The regional reliability standards development procedure shall provide for reasonable notice and opportunity for public comment At a minimum the procedure shall include public notice of the intent to develop a standard a public comment period on the proposed standard due consideration of those public comments and a ballot of interested stakeholders





See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 2nd para - Due process (Page 8)

Fair due process - The ReliabilityFirst standards development process shall provide for reasonable notice and opportunity for public comment At a minimum the procedure shall include public notice of the intent to develop a standard a public comment period on the proposed standard due consideration of those public comments and a ballot of interested stakeholders


bull Transparent mdash All actions material to the development of regional reliability standards shall be transparent All standards development meetings shall be open and publicly noticed on the regional entityrsquos Web site


See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 6th para - Transparent (Page 9)

Transparent - All actions material to the development of ReliabilityFirst Standards shall be transparent All standards development meetings shall be open and publicly noticed on ReliabilityFirstrsquos Web site


bull Does not unnecessarily delay development of the proposed reliability standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


Does not unnecessarily delay development of the proposed Standard

COMMON ATTRIBUTE 28 Each standard shall enable or support one or more of the reliability principles thereby ensuring that each standard serves a purpose in support of the reliability of the regional bulk power system Each standard shall also be consistent with all of the reliability principles thereby ensuring that no standard undermines reliability through an unintended consequence







Each standard shall enable or support one or more of the reliability principles thereby ensuring that each standard serves a purpose in support of the reliability of the regional BPS Each standard shall also be consistent with all of the reliability principles thereby ensuring that no standard undermines reliability through an unintended consequence

COMMON ATTRIBUTE 29 While reliability standards are intended to promote reliability they must at the same time accommodate competitive electricity markets Reliability is a necessity for electricity markets and robust electricity markets can support reliability Recognizing that bulk power system reliability and electricity markets are inseparable and mutually interdependent all regional reliability standards shall be consistent with NERCrsquos market interface principles Consideration of the market interface principles is intended to ensure that standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


While ReliabilityFirst Standards are intended to promote reliability they must at the same time accommodate competitive electricity markets Reliability is a necessity for electricity markets and robust electricity markets can support reliability Recognizing that BPS reliability and electricity markets are inseparable and mutually interdependent all ReliabilityFirst Standards shall be consistent with NERCrsquos market interface principles Consideration of the market interface principles is intended to ensure that standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets

COMMON ATTRIBUTE 30 To ensure uniformity of regional reliability standards a regional reliability standard shall consist of the elements identified in this section of the procedure These elements are intended to apply a systematic discipline in the development and revision of standards This discipline is necessary to achieving standards that are measurable enforceable and consistent





See ReliabilityFirst Procedure Format Requirements of an Organizational Standard 1st para (Page 3)

A Standard shall consist of the format requirements shown in the Regional Reliability Standard Template These requirements apply to the development and revision of Standards These requirements are necessary to achieve Standards that are measurable enforceable and consistent Supporting documents to aid in the implementation of a Standard may be referenced by the Standard but are not part of the Standard itself The most current version of the approved NERC Reliability Standard template and its associated elements posted on the NERC website will be used at the time of the development of a ReliabilityFirst Regional Reliability Standard if different from the elements listed below

COMMON ATTRIBUTE 31 All mandatory requirements of a regional reliability standard shall be within the standard Supporting documents to aid in the implementation of a standard may be referenced by the standard but are not part of the standard itself



COMMON ATTRIBUTE 32 Applicability Clear identification of the functional classes of entities

responsible for complying with the standard noting any specific additions or exceptions If not applicable to the entire [Regional Entity Name] area then a clear identification of the portion of the bulk power system to which the standard applies Any limitation on the applicability of the standard




based on electric facility requirements should be described


See ReliabilityFirst Manual Format Requirements of an Organizational Standard Organizational Standard Format Requirement Template Row 3 - Applicability (Page 4) Applicability

Clear identification of the functional classes of entities responsible for complying with the Standard noting any specific additions or exceptions If not applicable to the entire ReliabilityFirst area then a clear identification of the portion of the BPS to which the Standard applies Any limitation on the applicability of the Standard based on electric facility requirements should be described

COMMON ATTRIBUTE 33 Measure(s) Each requirement shall be addressed by one or more

measures Measures are used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measure will identify to whom the measure applies and the expected level of performance or outcomes required demonstrating compliance Each measure shall be tangible practical and as objective as is practical It is important to realize that measures are proxies to assess required performance or outcomes Achieving the measure should be a necessary and sufficient indicator that the requirement was met Each measure shall clearly refer to the requirement(s) to which it applies


See ReliabilityFirst Procedure Format Requirements of an Organizational Standard Organizational Standard Format Requirement Template Row 8 - Measures (Page 5)


Measure(s)

Each requirement shall be addressed by one or more measurements Measurements that will be used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measurement identifies to whom the measurement applies Each measurement shall be tangible practical and as objective as is practical Achieving the full compliance level of each measurement should beis a necessary and sufficient indicator that the requirement was met

COMMON ATTRIBUTE 34 Compliance Monitoring Process

Defines for each measure bull The specific data or information that is required to

measure performance or outcomes bull The entity that is responsible for providing the data

or information for measuring performance or outcomes

bull The process that will be used to evaluate data or information for the purpose of assessing performance or outcomes

bull The entity that is responsible for evaluating data or information to assess performance or outcomes

bull The time period in which performance or outcomes is measured evaluated and then reset

bull Measurement data retention requirements and assignment of responsibility for data archiving


See ReliabilityFirst Procedure Format Requirements of an Organizational Standard Compliance Administration Elements Row 1 - Compliance Monitoring Process (Page 6)


Defines for each measure bull The specific data or information that is

required to measure performance or outcomes

bull The entity that is responsible to provide the data or information for measuring


performance or outcomes bull The process that will be used to evaluate

data or information for the purpose of assessing performance or outcomes



bull Measurement dData retention requirements and assignment of responsibility for data archiving

bull Violation severity levels

116-390 Village Blvd Princeton NJ 08540 6094528060 | wwwnerccom

Comment Period Opens for Proposed Amendments to NERC Rules of Procedure Appendices 3B and 3D Comments Due April 15 2011 NERC is herby requesting comments on two proposed revisions to the NERC Rules of Procedure to amend Appendix 3B Election Procedure for Members of NERC Standards Committee and to add Appendix 3D Registered Ballot Body Criteria The proposed Appendices 3B and 3D are being posted for a forty-five day comment period that will close on April 15 2011 NERC Management plans on presenting these proposed changes to the NERC Board of Trustees for approval at the May 11 2011 Board of Trustees meeting Appendix 3B Election Procedure for Members of NERC NERC is requesting public comments on the proposed changes to the Procedure for Election of Members of the NERC Standards Committee (ldquoSC Election Procedurerdquo) which is included in the NERC Rules of Procedure as Appendix 3B There are three proposed substantive changes to the SC Election Procedure

1) The first proposed change would require the chairman and vice chairman to serve as non-voting members of the Standards Committee The purpose of this change is to clarify that the Standard Committeersquos officers are expected to act in support of the electric reliability organization rather than in support of any particular industry segment

2) The second proposed change would require a Canadian representative on the Standards Committee to be any company or association incorporated in Canada any agency of a federal provincial or local government in Canada or any person with Canadian citizenship who is residing in Canada

3) The third proposed change simplifies the process of filling vacant Standards Committee positions by eliminating the need to collect petitions and hold a ratification vote

Other minor conforming changes are also being proposed to Appendix 3B Appendix 3D Registered Ballot Body Criteria On September 3 2010 the Federal Energy Regulatory Commission (ldquoFERCrdquo) approved NERCrsquos Standard Processes Manual to replace the previous FERC approved Reliability Standards Development Procedure Version 7 which was included as Appendix 3A to the NERC Rules of Procedure The Reliability Standards Development Procedure Version 7 included the

-2-

Registered Ballot Body Criteria as part of the Rules of Procedure However the new Standard Processes Manual excluded the Registered Ballot Body criteria NERC has determined that these criteria need to be reincorporated into the NERC Rules of Procedure NERC is proposing to include the Registered Ballot Body Criteria as a new Appendix 3D Registered Ballot Body Criteria The proposed criteria are included with this posting for comment In addition to clarifying changes the proposed changes include the following

1) Individuals are added to the criteria of potential Registered Ballot Body members

2) In the Segment Qualification Guidelines clarification was added that individuals or entities that elect to participate in Segment 8 are not eligible to participate in multiple segments

3) In the Segment Qualification Guidelines clarification was added to state that after

members of each segment are selected registered participants may apply to change these segments annually on a schedule determined by the Standards Committee

4) Several places in the criteria were clarified to include ISOs to those areas that were

previously limited to RTOs 5) A new criterion was added to Segment 3 allowing agents or associations to represent

groups of LSEs 6) Segment 5 was clarified to include variable and other renewable resources 7) A new criterion was added to Segment 5 allowing agents or associations to represent

groups of electric generators 8) A new criterion was added to Segment 6 allowing agents or associations to represent

groups of electricity brokers aggregators or marketers Segment 6 also adds a provision that this segment includes demand-side management providers

9) Segment 8 was clarified to include a provision that individuals or entities such as

consultants or vendors providing products or services related to bulk power system reliability within the previous 12 months to another entity eligible to joint Segments 1 through 7 (and therefore eligible to join one of those segments) are not eligible to join Segment 8

10) Regional reliability organizations were replaced in Segment 10 with regional entities

Submission of Comments Comments are due April 15 2011 and must be submitted electronically to ropcommentsnercnet NERC intends to submit these proposed Rule of Procedure changes to the NERC Board of Trustees for approval at its May 11 2011 meeting For additional information please contact Elizabeth Heenan at elizabethheenannercnet

Proposed Appendix 3B

Procedures for Election of Members of the Standards Committee (CLEAN)

PPrroocceedduurreess ffoorr EElleeccttiioonn ooff MMeemmbbeerrss ooff tthhee SSttaannddaarrddss CCoommmmiitttteeee

Appendix 3B

Procedures for Election of Members of the Standards Committee

Procedure for Election of Standards Committee Members 2 March 2011



TTaabbllee ooff CCoonntteennttss

Purpose 4

Responsibilities for This Procedure 4

Guiding Principles 4

Standards Committee Membership 4

Standards Committee Membership Term 5

Standards Committee Officers 5

Standards Committee Scope and Conduct of Business 5

Segment Representative Nominations 5

Segment Representative Elections 6

Election Formula 7

Representation from Canada 8

Special Elections 8

Alternative Procedures 8


Purpose This procedure is provided for use by the NERC Standards Registered Ballot Body to facilitate the election of industry stakeholder segment (Segment)1

Responsibilities for This Procedure

representatives to the NERC Standards Committee This procedure is a default process that is available on a voluntary basis for the benefit of all Segments of the Registered Ballot Body The use of alternative procedures is described in a later section

The NERC Board of Trustees provides oversight of the election of Standards Committee members The Board provides the authority for approval of this procedure and any revisions thereto and monitors any Segment-specific procedures that may be developed to ensure they are consistent with established principles The Standards Committee shall be responsible for advising the Board regarding the use of this procedure or any revisions to the procedure Each Registered Ballot Body entity shall be responsible for actively participating in the nomination and election of Standards Committee representatives for each Segment in which the entity is a member The Standards Process Manager (SPM) shall administer the implementation and maintenance of this procedure

Guiding Principles This procedure supports a standards development process that is open inclusive balanced and fair This procedure shall be interpreted in a manner that is consistent with NERCrsquos mission of promoting the reliability of the North American bulk electric systems NERC Reliability Standards Development Procedure NERCrsquos Reliability and Market Interface Principles and maintaining good standing as a standards developer accredited by the American National Standards Institute

Standards Committee Membership Each valid2

1 Industry stakeholder Segment criteria and a list of entities in the NERC Standards Registered Ballot Body are provided on the NERC web site In this procedure the term ldquoSegmentrdquo shall mean one of the currently defined industry stakeholder Segments

Segment shall be eligible to elect two voting members to represent the Segment on the Standards Committee A registered entity may provide only one Standards Committee member irrespective of the number of segments in which the entity is registered Each representative that is elected by a Segment to fill one of those positions shall serve on behalf of the Registered Ballot Body entities in that Segment An eligible position on the committee that is not filled by a Segment shall be shown as vacant and shall not be counted in the determination of a quorum Each elected member of the Standards Committee shall carry one vote

2 Validity is determined by established Segment criteria including the minimum number of entities in a Segment


Standards Committee Membership Term The Standards Committee reports to the NERC Board of Trustees and is responsible for managing the NERC Reliability Standards Development Procedure and other duties as assigned by the Board The Standards Committee also serves for the benefit of the members of the Registered Ballot Body and is accountable to them through election by the Segment representatives Standards Committee membership shall be for a term of two years with membersrsquo terms staggered such that half of the member positions (one per Segment) are refilled each year by Segment election Prior to the end of each term nominations will be received and an election held in accordance with this procedure or a qualified Segment procedure to elect Standards Committee representatives for the next term There is no limit on the number of two-year terms that a member of the Standards Committee may serve although the setting of limits in the future is not precluded

Standards Committee Officers Approximately 90 days prior to the end of each term the Standards Committee shall elect a chairman and vice chairman to serve as officers and preside over the business of the committee for the following year The officers shall serve a term of one year without limit on the number of terms an officer may serve although the setting of limits in the future is not precluded The chairman and vice chairman shall serve as non-voting members of the Standards Committee The SPM serves as a non-voting member and secretary of the Standards Committee

Standards Committee Scope and Conduct of Business The Standards Committee conducts its business in accordance with a separate scope document the Reliability Standards Development Procedure other applicable NERC procedures and procedures that the committee itself may develop This procedure addresses the nomination and election of members of the committee and is not intended to otherwise establish or limit the scope authorities or procedures of the committee

Segment Representative Nominations Approximately 90 days prior to the start of each term the SPM shall request nominations to fill Standards Committee positions that will become open with the expiration of the current term Notice of the nominations process shall be announced to the Registered Ballot Body and to others that may be interested in standards for the reliability of North American bulk electric systems The SPM shall post the announcement on the NERC web page and distribute the announcement to applicable NERC e-mail lists The announcement shall include a brief description of the responsibilities of the Standards Committee and estimates of the work effort and travel expected of Standards Committee members Any person or entity may submit a nomination Self-nominations are encouraged To be eligible for nomination a nominee shall be an employee or agent of an entity registered in the applicable Segment To allow verification of affiliation a nominee shall be a registered User in the NERC Registered Ballot Body It is not required that the nominee be the same person as the entityrsquos Registered Ballot Body representative for that Segment


The SPM shall provide a method for the submittal of nominations preferably an on-line nominations form using Internet protocols The nomination form shall request the following information and other information that the SPM deems necessary to completing the election process

Nomination Information 1 Segment for which the nomination is made

2 Nominee name (selected from list of registrants)

3 Nominee job title 3

4 Nominee organization (must be an entity registered in the designated Segment) 3

5 Nominee contact information telephone fax e-mail and mailing address3

6 Nominee brief summary of qualifications related to serving on the Standards Committee (limited to a 3000-character text box approximately 500 words or one-page single-spaced)

7 Indication (check box) that the nominee has been contacted and is willing to serve on the Standards Committee for a two-year term

8 Person or entity making the nomination

9 Contact information for person or entity making nomination contact name organization telephone fax e-mail and mailing address

The SPM shall verify that each nomination received is complete and valid The SPM may follow up with nominees to collect additional information In the event that multiple nominations are received for persons from a single entity within a Segment that entityrsquos representative shall determine which person will be the nominee from that entity The SPM shall post each nomination that is complete and valid Each nomination shall be posted as soon as practical after it has been verified The nomination period shall remain open for 21 calendar days from the announced opening of the nominations at which time the nominations shall be closed

Segment Representative Elections The SPM shall prepare a slate of nominees for each Segment The Segment slate shall consist of all valid nominations received for that Segment without prejudice in the method of listing the slate The SPM shall provide an electronic ballot form for each Segment listing the slate of nominees Each Registered Ballot Body entity in a Segment may cast one vote per Standards Committee member position being filled (ie one vote if one position is being filled and two votes if two 3 Information items 3ndash5 are provided automatically from the nominee during registration


positions are being filled) In the case that an entity casts two votes within a Segment each vote must be for a different candidate in that Segment (ie an entity cannot vote twice for a nominee within a Segment) This ballot procedure is repeated for each Segment in which an entity is a member of the Registered Ballot Body The ballot for each Segment is conducted independently from the ballots of other Segments Only the entities in the Registered Ballot Body for a Segment may vote in that Segment The ballot period shall be announced to the Registered Ballot Body and to others that may be interested in standards for the reliability of North American bulk electric systems The SPM shall post the announcement on the NERC web page and distribute the announcement to applicable NERC e-mail lists The ballot period shall remain open for ten calendar days from the announced opening of the ballot period at which time the ballot period shall be closed Votes may be cast by the Registered Ballot Body Representative for each entity or a proxy designated by the representative An entity may vote in each Segment in which it is registered Ballot results shall remain confidential during the ballot period As soon as practical after the close of the ballot period the SPM shall publicly post the election results for each Segment (ie the names of elected members and slates for any run-off elections that may be required)

Election Formula The elected Standards Committee member for each Segment shall be the nominee receiving the highest total number of votes with the condition that the nominee must receive a vote from a simple majority of the entities casting a vote in that Segment If the election is being held for two positions in a Segment the nominees receiving the highest and second highest number of votes shall be elected with the condition that each nominee must receive a vote from a simple majority of the entities casting a vote in that Segment4

In this case if only one of the two nominees meets these criteria then that nominee shall be deemed elected

In the event that the election is incomplete in a Segmentrsquos first ballot (no candidate or only one candidate meets the criteria) then a second ballot will be conducted in that Segment using a process similar to that previously described If two positions are remaining to be filled in the second ballot the slate of candidates shall consist of the four candidates receiving the highest number of votes in the first ballot If one position is remaining to be filled in the second ballot the slate shall consist of the two candidates receiving the highest number of votes A candidate who was elected in the first ballot is considered elected and is excluded from the second ballot In the event of a tie that precludes choosing the top four (or two) candidates the slate will be expanded to include those candidates that are tied After the second ballot in the Segment the candidate(s) receiving the highest number of votes shall be elected to fill the remaining position(s) in that Segment 4 Each entity in the Segment is allowed to cast two votes This criterion means that more than fifty percent (gt50) of the entities cast one of their votes for that nominee


In the event of a tie between two or more candidates after a second ballot a run-off ballot may be used to break the tie The position shall remain vacant until the tie is broken by the Segment

Representation from Canada To achieve balance of representation between the United States and Canada on the basis of net energy for load (NEL) the following special procedure shall apply

1 If any regular election of Standards Committee members does not result in at least two Canadian members being elected the Canadian nominees receiving the next highest percentage of votes within their respective Segment(s) will be designated as members as needed to achieve a total of two Canadian members

2 Each such specially designated Canadian member of the Standards Committee shall have a one year term as the Standards Committee holds elections each year and special designation of members should not interfere with the regular election process

3 If any segment as defined in Appendix B of the Reliability Standards Development Procedure has an unfilled position following the annual Standards Committee election the first preference is to assign each specially designated Canadian representative to an unfilled segment for which he or she qualifies

4 Any such specially designated members of the Standards Committee shall have the same rights and obligations as all other members of the Standards Committee

5 For the purpose of the Standards Committee election process Canadian representation shall be defined as any company or association incorporated in Canada any agency of a federal provincial or local government in Canada or any person with Canadian citizenship who is residing in Canada

Special Elections

The Standards Committeersquos officers shall determine the need for a special election to fill a vacant Standards Committee position between regular elections considering among other things the timing of the last and the next regular election If a need is determined the Standards Committee officers shall communicate a request to the Director of Standards who shall initiate a process to conduct the election The SPM shall post a request for nominations on the NERC web page and distribute the announcement to applicable NERC e-mail lists eg the ballot body of the Segment(s) involved The election will be held 30 days after the announcement and shall use the same election process and formula employed in regular elections The Board of Trustees shall be notified of the election results

Alternative Procedures This procedure is provided as the default method for Segments to elect representatives to the Standards Committee Alternative procedures may be used by a Segment or jointly by several Segments Such a procedure shall be consistent with the principles noted in this document Such a procedure shall be ratified by at least two-thirds of the registered entities in each Segment in which it will be applied and is subject to review by the NERC Board


Procedures for Election of Members of the Standards Committee (REDLINE)

PPrroocceedduurreess ffoorr EElleeccttiioonn Procedure for ooff MMeemmbbeerrss ooff tthhee NERC SSttaannddaarrddss CCoommmmiitttteeee

Appendix 3B

Table of ContentsProcedures for Election of Members of the Standards Committee

November 1 2005 2 March 2011

Effective January 18 2007




Purpose 4













Election of Members of the NERC Standards Committee Procedures








1 Industry stakeholder Segment criteria and a list of entities in the NERC Standards Registered Ballot Body are provided aton the NERC website and in Appendix 3D to the NERC Rules of Procedure In this procedure the term ldquoSegmentrdquo shall mean one of the currently defined industry stakeholder Segments






Standards Committee Officers At the beginning of each annual Approximately 90 days prior to the end of each term the Standards Committee shall as a first order of business elect a chairman and vice chairman to serve as officers and preside over the business of the committee for the following year The officers shall serve a term of one year without limit on the number of terms an officer may serve although the setting of limits in the future is not precluded The chairman and vice chairman shall serve as non-voting members of the Standards Committee The SPM serves as a non-voting member and secretary of the Standards Committee


Segment Representative Nominations Approximately 90 days prior to the start of each term the SPM shall request nominations to fill Standards Committee positions that will become open with the expiration of the current term Notice of the nominations process shall be announced to the Registered Ballot Body and to others that may be interested in standards for the reliability of North American bulk electric systems The SPM shall post the announcement on the NERC web page and distribute the announcement to applicable NERC e-mail lists The announcement shall include a brief description of the responsibilities of the Standards Committee and estimates of the work effort and travel expected of Standards Committee members Any person or entity may submit a nomination Self-nominations are encouraged To be eligible for nomination a nominee shall be an employee or agent of an entity registered in the applicable Segment To allow verification of affiliation a nominee shall be a registered User



in the NERC Registered Ballot Body It is not required that the nominee be the same person as the entityrsquos Registered Ballot Body representative for that Segment The SPM shall provide a method for the submittal of nominations preferably an on-line nominations form using Internet protocols The nomination form shall request the following information and other information that the SPM deems necessary to completing the election process











Segment Representative Elections The SPM shall prepare a slate of nominees for each Segment The Segment slate shall consist of all valid nominations received for that Segment without prejudice in the method of listing the slate

3 Information items 3ndash5 are provided automatically from the nominee during registration



The SPM shall provide an electronic ballot form for each Segment listing the slate of nominees Each Registered Ballot Body entity in a Segment may cast one vote per Standards Committee member position being filled (ie one vote if one position is being filled and two votes if two positions are being filled) In the case that an entity casts two votes within a Segment each vote must be for a different candidate in that Segment (ie an entity cannot vote twice for a nominee within a Segment) This ballot procedure is repeated for each Segment in which an entity is a member of the Registered Ballot Body The ballot for each Segment is conducted independently from the ballots of other Segments Only the entities in the Registered Ballot Body for a Segment may vote in that Segment The ballot period shall be announced to the Registered Ballot Body and to others that may be interested in standards for the reliability of North American bulk electric systems The SPM shall post the announcement on the NERC web page and distribute the announcement to applicable NERC e-mail lists The ballot period shall remain open for ten calendar days from the announced opening of the ballot period at which time the ballot period shall be closed Votes may be cast by the Registered Ballot Body Representative for each entity or a proxy designated by the representative An entity may vote in each Segment in which it is registered Ballot results shall remain confidential during the ballot period As soon as practical after the close of the ballot period the SPM shall publicly post the election results for each Segment (ie the names of elected members and slates for any run-off elections that may be required)



In the event that the election is incomplete in a Segmentrsquos first ballot (no candidate or only one candidate meets the criteria) then a second ballot will be conducted in that Segment using a process similar to that previously described If two positions are remaining to be filled in the second ballot the slate of candidates shall consist of the four candidates receiving the highest number of votes in the first ballot If one position is remaining to be filled in the second ballot the slate shall consist of the two candidates receiving the highest number of votes A candidate who was elected in the first ballot is considered elected and is excluded from the second ballot In the event of a tie that precludes choosing the top four (or two) candidates the slate will be expanded to include those candidates that are tied

4 Each entity in the Segment is allowed to cast two votes This criterion means that more than fifty percent (gt50) of the entities cast one of their votes for that nominee



After the second ballot in the Segment the candidate(s) receiving the highest number of votes shall be elected to fill the remaining position(s) in that Segment In the event of a tie between two or more candidates after a second ballot a run-off ballot may be used to break the tie The position shall remain vacant until the tie is broken by the Segment







Special Elections Between regularly scheduled elections a Segment may hold a special election to replace an existing member or fill a vacant position A special election request may be requested by petition of ten entities or 25 of the entities registered in a Segment whichever is less It is the responsibility of the requester(s) to collect the requisite number of signatories to the petition and submit it to the SPM If SPM receives a valid petition for a special election the SPM shall request that the Segment ratify the need for a special election Ratification requires approval by a two-thirds majority of the entities registered in the Segment If the request is ratified by the Segment the SPM shall initiate the request for nominations and election as described later in this procedure

The Standards Committeersquos officers shall determine the need for a special election to fill a vacant Standards Committee position between regular elections considering among other things the timing of the last and the next regular election If a need is determined the Standards Committee officers shall communicate a request to the Director of Standards who shall initiate a process to conduct the election The SPM shall post a request for nominations on the NERC web



page and distribute the announcement to applicable NERC e-mail lists eg the ballot body of the Segment(s) involved The election will be held 30 days after the announcement and shall use the same election process and formula employed in regular elections The Board of Trustees shall be notified of the election results


Proposed Appendix 3D

Development of the Registered

Ballot Body (CLEAN)

AAppppeennddiixx 33DD mdashmdash DDeevveellooppmmeenntt ooff tthhee RReeggiisstteerreedd BBaalllloott BBooddyy1

Registration Procedures

1

The Registered Ballot Body comprises all organizations entities and individuals that

1 Qualify for one of the segments and

2 Are registered with NERC as potential ballot participants in the voting on standards and

3 Are current with any designated fees

Each participant when initially registering to join the Registered Ballot Body and annually thereafter shall self-select to belong to one of the segments described below

NERC general counsel will review all applications for joining the Registered Ballot Body and make a determination of whether the self-selection satisfies at least one of the guidelines to belong to that segment The entity will then be ldquocredentialedrdquo to participate as a voting member of that segment The Standards Committee will decide disputes with an appeal to the Board of Trustees

All registrations will be done electronically

Segment Qualification Guidelines

1 The segment qualification guidelines are inclusive ie any entity or individual with a legitimate interest in the reliability of the bulk power system that can meet any one of the guidelines for a segment is entitled to belong to and vote in that segment

2 Corporations or organizations with integrated operations or with affiliates that qualify to belong to more than one segment (eg transmission owners and load serving entities) may belong to each of the segments in which they qualify provided that each segment constitutes a separate membership and is represented by a different representative Individuals or entities that elect to participate in Segment 8 are not eligible to participate in multiple segments

3 At any given time affiliated entities may collectively be registered only once within a segment

4 Any individual or entity such as a consultant or vendor providing products or services related to bulk power system reliability within the previous 12 months to another entity eligible to join Segments 1 through 7 shall be qualified to join any one segment for which one of the entities receiving those products or services is qualified to join

5 Corporations organizations entities and individuals may participate freely in all subgroups

6 After their initial selection registered participants may apply to change segments annually on a schedule determined by the Standards Committee

7 The qualification guidelines and rules for joining segments will be reviewed periodically to ensure that the process continues to be fair open balanced and inclusive Public input will be solicited in the review of these guidelines

8 Since all balloting of standards will be done electronically any registered participant may designate a proxy to vote on its behalf There are no limits on how many proxies a person may hold However NERC must have in its possession either in writing or by email documentation that the voting right by proxy has been transferred

1 The segment qualification guidelines were proposed in the final report of the NERC Standing Committees Representation Task Force on February 7 2002 The Board of Trustees endorsed the industry segments and weighted segment voting model on February 20 2002 and may change the model from time to time

Segments

Segment 1 Transmission Owners

a Any entity that owns or controls at least 200 circuit miles of integrated transmission facilities or has an Open Access Transmission Tariff or equivalent on file with a regulatory authority

b Transmission owners that have placed their transmission under the operational control of an RTO or ISO

c Independent transmission companies or organizations merchant transmission developers and transcos that are not RTOs or ISOs

d Excludes RTOs and ISOs that are eligible to join to Segment 2 Segment 2 Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)

a Any entity authorized by appropriate governmental authority to operate as an RTO or ISO Segment 3 Load-Serving Entities (LSEs)

a Entities serving end-use customers under a regulated tariff a contract governed by a regulatory tariff or other legal obligation to serve

b A member of a generation and transmission (GampT) cooperative or a joint-action agency is permitted to designate the GampT or joint-action agency to represent it in this segment such designation does not preclude the GampT or joint-action agency from participation and voting in another segment representing its direct interests

c Agents or associations can represent groups of LSEs Segment 4 Transmission Dependent Utilities (TDUs)

a Entities with a regulatory contractual or other legal obligation to serve wholesale aggregators or customers or end-use customers and that depend primarily on the transmission systems of third parties to provide this service

b Agents or associations can represent groups of TDUs Segment 5 Electric Generators

a Affiliated and independent generators including variable and other renewable resources

b A corporation that sets up separate corporate entities for each one or two generating plants in which it is involved may only have one vote in this segment regardless of how many single-plant or multiple-plant corporations the parent corporation has established or is involved in

c Agents or associations can represent groups of electrical generators Segment 6 Electricity Brokers Aggregators and Marketers

a Entities serving end-use customers under a power marketing agreement or other authorization not classified as a regulated tariff

b An entity that buys sells or brokers energy and related services for resale in wholesale or retail markets whether a non-jurisdictional entity operating within its charter or an entity licensed by a jurisdictional regulator

c GampT cooperatives and joint-action agencies that perform an electricity broker aggregator or marketer function are permitted to belong to this segment

d Agents or associations can represent groups of electricity brokers aggregators or marketers

e This segment also includes demand-side management providers

Segment 7 Large Electricity End Users

a At least one service delivery taken at 50 kV (radial supply or facilities dedicated to serve customers) that is not purchased for resale

b A single customer with an average aggregated service load (not purchased for resale) of at least 50000 MWh annually excluding cogeneration or other back feed to the serving utility

c Agents or associations can represent groups of large end users Segment 8 Small Electricity Users

a Service taken at below 50 kV

b A single customer with an average aggregated service load (not purchased for resale) of less than 50000 MWh annually excluding cogeneration or other back feed to the serving utility

c Agents state consumer advocates or other advocate groups can represent groups of small customers

d Any entity or person currently employed by an entity that is eligible to join one or more of the other nine segments shall not be qualified to join Segment 8

e Any individual or entity such as a consultant or vendor providing products or services related to bulk power system reliability within the previous 12 months to another entity eligible to join Segments 1 through 7 shall be qualified to join any one segment for which one of the entities receiving those products or services is qualified to join and shall not be eligible to join segment 8

Segment 9 Federal State and Provincial Regulatory or other Government Entities

a Does not include federal power management agencies or the Tennessee Valley Authority

b May include public utility commissions Segment 10 Regional Entities

a Any entity that is a regional entity as defined in NERCrsquos Bylaws It is recognized that there may be instances in which an entity is both an RTO or ISO and a regional entity In such a case the two functions must be sufficiently independent to meet NERCrsquos Rules of Procedure and applicable regulatory requirements as evidenced by the approval of a regional entity delegation agreement Without such an approval the entity shall be limited to choosing to enter one segment or the other but not both



Ballot Body (REDLINE)

AAppppeennddiixx 33DDBB mdashmdash DDeevveellooppmmeenntt ooff tthhee RReeggiisstteerreedd BBaalllloott BBooddyy1


1

The Registered Ballot Body comprises all organizations and entities and individuals that




Each participant when initially registering to join the Registered Ballot Body and annually thereafter will shall self-select to belong to one of the segments described abovebelow





The general guidelines for all segments are


2 3 At any given time affiliated entities may collectively be registered only once within a segment

3 4 Any person individual or entity such as a consultant or vendor providing products or services related to bulk

power system reliability within the previous 12 months to another entity eligible to join Segments 1 tothrough 7 shall be qualified to join any one segment for which one of the entities receiving those products or services is qualified to join

4 5 Corporations organizations and entities and individuals may participate freely in all subgroups

5

1 The segment qualification guidelines were proposed in the final report of the NERC Standing Committees Representation Task Force on February 7 2002 The Board of Trustees endorsed the industry segments and weighted segment voting model on February 20 2002 and may change the model from time to time The latest version (approved or endorsed by the NERC Board of Trustees) shall be used in the NERC Reliability Standards Development Procedure

6 After their initial selection registered participants may apply to change segments annually according to a defined scheduleon a schedule determined by the Standards Committee

6 7 The qualification guidelines and rules for joining segments will be reviewed periodically to ensure that the

process continues to be fair open balanced and inclusive Public input will be solicited in the review of these guidelines

7 8 Since all balloting of standards will be done electronically any registered participant may designate a proxy to

vote on its behalf There are no limits on how many proxies a person may hold However NERC must have in its possession either in writing or by email documentation that the voting right by proxy has been transferred

Segments





d Excludes RTOs and ISOs (that are eligible to join to Segment 2) Segment 2 Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)




bc Agents or associations can represent groups of LSEs Segment 4 Transmission Dependent Utilities (TDUs)




b A corporation that sets up separate corporate entities for each one or two generating plants in which it is involved may only have one vote in this segment regardless of how many single-plant or twomultiple-plant corporations the parent corporation has established or is involved in

bc Agents or associations can represent groups of electrical generators

Segment 6 Electricity Brokers Aggregators and Marketers













d Any entity or person currently employed by an entity that is eligible to join one or more of the other eight nine segments shall not be qualified to join Segment 8

de Any individual or entity such as a consultant or vendor providing products or services related to bulk power system reliability within the previous 12 months to another entity eligible to join Segments 1 through 7 shall be qualified to join any one segment for which one of the entities receiving those products or services is qualified to join and shall not be eligible to join segment 8



b May include public utility commissions Segment 10 Regional Reliability Organizations and Regional Entities

a Any entity that is a regional reliability organization or regional entity as defined in NERCrsquos Bylaws It is recognized that there may be instances in which an entity is both an RTO or ISO and a regional entity or regional reliability organization In such a case the two functions must be sufficiently independent to meet NERCrsquos Rules of Procedure and applicable regulatory requirements as evidenced by the approval of a regional entity delegation agreement Without such an approval the entity shall be limited to choosing to enter one segment or the other but not both

From Guy V ZitoTo rscSubject FW Comment Period Opens for Proposed Changes to NERC Rules of Procedure Appendices 3B and 3DDate Tuesday March 01 2011 72758 PM

RSC Members Lets discuss at the next RSC meeting-Lee please add to our agenda I believe the proposed changes to the NERC SC election procedureare beneficial in addressing some issues that have been expressed by our members Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Elizabeth Heenan [ElizabethHeenannercnet]Sent Tuesday March 01 2011 605 PMTo Elizabeth HeenanSubject Comment Period Opens for Proposed Changes to NERC Rules of Procedure Appendices 3B and 3D

Comment Period Opens for Proposed Changes to NERC Rules of ProcedureAppendices 3B and 3D

NERC Stakeholders

Now available at httpwwwnerccomfilesFinal_Posting_Appendices_3B_3D_2011030120(3)pdf

NERC is requesting comments on two proposed revisions to the NERC Rules of Procedure to amend Appendix 3B Election Procedure forMembers of NERC Standards Committee and to add Appendix 3D Registered Ballot Body Criteria NERC is requesting public comments onthe proposed changes to the Procedure for Election of Members of the NERC Standards Committee (ldquoSC Election Procedurerdquo) which isincluded in the NERC Rules of Procedure as Appendix 3B NERC is also proposing to include the Registered Ballot Body Criteria as a newAppendix 3D Registered Ballot Body Criteria The proposed Appendices 3B and 3D are being posted for a forty-five day comment periodthat will close on April 15 2011 NERC Management plans on presenting these proposed changes to the NERC Board of Trustees forapproval at the May 11 2011 Board of Trustees meeting

Submission of Comments

Comments are due April 15 2011 and must be submitted electronically to ropcommentsnercnet NERC intends to submit theseproposed Rule of Procedure changes to the NERC Board of Trustees for approval at its May 11 2011 meeting




6094528060 | wwwnerccom ---You are currently subscribed to nercroster as gzitonpccorgTo unsubscribe send a blank email to leave-1249746-3920898eac8c94409e17058b6e89bfa4b2626listservnerccom

Attachment 1 Standard FAC-001-0 mdash Facility Connection Requirements

Adopted by NERC Board of Trustees February 8 2005 1 of 3 Effective Date April 1 2005

Note from the Project 2010-07 SDT The redline changes included in this document are the work of the Project 2010-07 SDT and are provided as a companion to the teamrsquos White Paper the aim is to provide an example to convey the direction of our proposal This is not intended to be a comprehensive rewrite of the standard

A Introduction

1 Title Facility Connection Requirements

2 Number FAC-001-0

3 Purpose To avoid adverse impacts on reliability Transmission Bulk Electric System Facility Oowners must establish facility connection and performance requirements

4 Applicability

41 Transmission Owner

4142 Generator Owner

5 Effective Date April 1 2005

B Requirements

R1 The Transmission Owner shall document maintain and publish facility connection requirements to ensure compliance with NERC Reliability Standards and applicable Regional Reliability Organization subregional Power Pool and individual Transmission Owner planning criteria and facility connection requirements The Transmission Ownerrsquos facility connection requirements shall address connection requirements for

R11 Generation facilities

R12 Transmission facilities and

R13 End-user facilities

R2 The Transmission Ownerrsquos facility connection requirements shall address but are not limited to the following items

R21 Provide a written summary of its plans to achieve the required system performance as described above throughout the planning horizon

R211 Procedures for coordinated joint studies of new facilities and their impacts on the interconnected transmission systems

R212 Procedures for notification of new or modified facilities to others (those responsible for the reliability of the interconnected transmission systems) as soon as feasible

R213 Voltage level and MW and MVAR capacity or demand at point of connection

R214 Breaker duty and surge protection

R215 System protection and coordination

R216 Metering and telecommunications

R217 Grounding and safety issues



R218 Insulation and insulation coordination

R219 Voltage Reactive Power and power factor control

R2110 Power quality impacts

R2111 Equipment Ratings

R2112 Synchronizing of facilities

R2113 Maintenance coordination

R2114 Operational issues (abnormal frequency and voltages)

R2115 Inspection requirements for existing or new facilities

R2116 Communications and procedures during normal and emergency operating conditions

R3 The Transmission Owner shall maintain and update its facility connection requirements as required The Transmission Owner shall make documentation of these requirements available to the users of the transmission system the Regional Reliability Organization and NERC on request (five business days)

R4 Generator Owner that receives an interconnection request for its facility shall within 45 days of such a request be required to comply with requirements R1 R2 and R3 for the facility for which it received the interconnection request

R3

C Measures

M1 The Transmission Owner shall make available (to its Compliance Monitor) for inspection evidence that it met all the requirements stated in Reliability Standard FAC-001-0_R1

M2 The Transmission Owner shall make available (to its Compliance Monitor) for inspection evidence that it met all requirements stated in Reliability Standard FAC-001-0_R2


M3M4 The Generator Owner that receives an interconnection request for its facility shall make available (to its Compliance Monitor) for inspection evidence that it met the requirements stated in Reliability Standard FAC-001-0 R4

D Compliance

1 Compliance Monitoring Process

11 Compliance Monitoring Responsibility

Compliance Monitor Regional Reliability Organization

12 Compliance Monitoring Period and Reset Timeframe

On request (five business days)

13 Data Retention

Formatted Indent Left 035 No bullets ornumbering



None specified

14 Additional Compliance Information

None

2 Levels of Non-Compliance

21 Level 1 Facility connection requirements were provided for generation transmission and end-user facilities per Reliability Standard FAC-001-0_R1 but the document(s) do not address all of the requirements of Reliability Standard FAC-001-0_R2

22 Level 2 Facility connection requirements were not provided for all three categories (generation transmission or end-user) of facilities per Reliability Standard FAC-001-0_R1 but the document(s) provided address all of the requirements of Reliability Standard FAC-001-0_R2

23 Level 3 Facility connection requirements were not provided for all three categories (generation transmission or end-user) of facilities per Reliability Standard FAC-001-0_R1 and the document(s) provided do not address all of the requirements of Reliability Standard FAC-001-0_R2

24 Level 4 No document on facility connection requirements was provided per Reliability Standard FAC-001-0_R3

E Regional Differences

1 None identified

Version History

Version Date Action Change Tracking

0 April 1 2005 Effective Date New

Attachment 2 FAC-003-2 mdash Transmission Vegetation Management

Draft 5 January 27 2011 1

Note from the Project 2010-07 SDT The redline changes included in this document are the work of the Project 2010-07 SDT and are provided as a companion to the teamrsquos White Paper the aim is to provide an example to convey the direction of our proposal This is not intended to be a comprehensive rewrite of the standard Any formal standard revision would require coordination with the work of the drafting team currently revising FAC-003-2 under Project 2007-07

Standard Development Timeline 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 15ndashFebruary 14 2007)

3 SAR posted for comment (April 10ndashMay 9 2007)

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

5 First draft of proposed standard posted (October 27 2008-November 25 2008))

6 Second draft of revised standard posted (September 10 20-October 24 2009)

7 Third draft of revised standard posted (March 1 2010-March 31 2010)

8 Forth draft of revised standard posted (June 17 2010-July 17 2010)

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

Recirculation ballot of standards January 2011

Receive BOT approval February 2011



Effective Dates

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



Vers ion His tory Version Date Action Change Tracking

1 TBA 1 Added ldquoStandard Development Roadmaprdquo

2 Changed ldquo60rdquo to ldquoSixtyrdquo in section A 52

3 Added ldquoProposed Effective Date April 7 2006rdquo to footer

4 Added ldquoDraft 3 November 17 2005rdquo to footer

012006

1 April 4 2007 Regulatory Approval mdash Effective Date New 2

FAC-003-2 mdash Transmission Vegetation Management

Draft 5 December 17 2010 4

Defin itions of Terms Us ed in Standard 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 Ownerrsquos 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 Ownerrsquos 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



In troduc tion 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

41 Functional Entities Transmission Owners

Generator Owners

42 Facilities Defined below (referred to as ldquoapplicable linesrdquo) including but not limited to those that cross lands owned by federal1

421 Overhead transmission lines operated at 200kV or higher

state provincial public private or tribal entities

422 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

423 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

424 This standard applies to overhead transmission lines identified above (421 through 423) 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 ldquoAccess approvals by Federal agenciesrdquo

Rationale -The areas excluded in 424 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 doesnrsquot makes the standard stronger as it relates to clarity

Formatted Normal Indent Left 0 SpaceAfter 0 pt Tab stops Not at 113



43 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 (ldquoStandardrdquo) 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 mdash defines a particular reliability objective or outcome to be achieved

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

c) Competency-based mdash 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

bull Performance-based Requirements 1 and 2

bull Competency-based Requirement 3

bull 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 ldquopublic landsrdquo 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 Standardrsquos emphasis is on vegetation grow-ins



Requirements and Meas ures R1 Each Transmission Owner and Generator

Owner shall manage 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

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 ndash High] [Time Horizon ndash Real-time]

M1 Each Transmission Owner and Generator 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

If a later confirmation of a Fault by the Transmission Owner or Generator 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

2 This requirement does not apply to circumstances that are beyond the control of a Transmission Owner or Generator 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 the Generator Owner or an applicable regulatory body ice storms and floods and 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 Ownerrsquos 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 TOrsquos 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



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)

R2 Each Transmission Owner and Generator

Owner shall manage 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 ndash Medium] [Time Horizon ndash Real-time]

M2 Each Transmission Owner and Generator 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







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 include(s) the following 31 Accounts for the movement of

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

32 Accounts for the inter-relationships between vegetation growth rates vegetation control methods and inspection frequency

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

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


Owner without any intentional time delay shall notify the control center holding switching authority for the associated applicable transmission line when the Transmission Owner or Generator Owner has confirmed the existence of a vegetation condition that is likely to cause a Fault at any moment

[VRF ndash Medium] [Time Horizon ndash Real-time] M4 Each Transmission Owner and Generator 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 Ownerrsquos 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 or Generator 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 or Generator Owner shall take corrective action to ensure continued vegetation management to prevent encroachments [VRF ndash Medium] [Time Horizon ndash Operations Planning] M5 Each Transmission Owner and

Generator 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)


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 ROW3

[VRF ndash Medium] [Time Horizon ndash Operations Planning] M6 Each Transmission Owner and

Generator Owner has evidence that it conducted Vegetation Inspections of the transmission line ROW for all applicable

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



transmission lines at least once per calendar year but with no more than 18 months between inspections on the same ROW Examples of acceptable forms of evidence may include completed and dated work orders dated invoices or dated inspection records (R6)


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

bull Change in expected growth rate environmental factors bull Circumstances that are beyond the control of a Transmission Owner or Generator

Owner4

bull Rescheduling work between growing seasons

bull Crew or contractor availability Mutual assistance agreements bull Identified unanticipated high priority work bull Weather conditionsAccessibility bull Permitting delays bull Land ownership changesChange in land use by the landowner bull Emerging technologies

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

M7 Each Transmission Owner and Generator 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 or Generator 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 GO 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



Compliance

Compliance Enforcement Authority

bull Regional Entity

Compliance Monitoring and Enforcement Processes

bull Compliance Audits bull Self-Certifications bull Spot Checking bull Compliance Violation Investigations bull Self-Reporting bull Complaints bull 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 Entityrsquos 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 mdash 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 andor outside of the ROW



o Category 1B mdash 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 andor outside of the ROW

o Category 2A mdash 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 mdash 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 mdash Fall-ins Sustained Outages caused by vegetation falling into applicable transmission lines from outside the ROW

o Category 4A mdash 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 mdash 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 Viola tion Ris k Factors and Viola tion Severity Leve ls

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 Ownerrsquos applicable lines

movement of transmission line conductors under their Rating and all Rated Electrical Operating Conditions for the Transmission Ownerrsquos applicable lines

encroachment of vegetation into the MVCD for the Transmission Ownerrsquos applicable lines


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 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 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 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)



Variances None In te rpre ta tions 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 (ldquoMVCDrdquo) of transmission lines R1 is applicable to lines ldquoidentified 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 Outagerdquo 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 Ownerrsquos vegetation programrsquos ability to meet the goal of ldquopreventing a Sustained Outage that could lead to Cascadingrdquo Thus violation severity increases with a Transmission Ownerrsquos 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 conductorrsquos 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 velocitydirection 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 Ownerrsquos 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 Ownerrsquos 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

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

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

bull Documenting and tracking the specific action taken for each location bull 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 andor 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

bull 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 Ownerrsquos 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 2000 miles of 230 kV transmission lines this Transmission Owner will be responsible for inspecting all 2000 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 1002000 = 005 or 5 The ldquoLow VSLrdquo 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 ldquospan-by-spanrdquo or even a ldquoline-by-linerdquo 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 Ownerrsquos 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 Ownerrsquos 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 mdashmdash TTAABBLLEE 22 mdashmdash MMiinniimmuumm VVeeggeettaattiioonn CClleeaarraannccee DDiissttaanncceess ((MMVVCCDD))5

For Alternating Current Voltages

5

( AC ) Nominal System Voltage (kV)

( AC ) Maximum System Voltage (kV)

MVCD feet

(meters)

sea level

MVCD

feet (meters) 3000ft

(9144m)

MVCD


(12192m)

MVCD


(1524m)

MVCD


(18288m)

MVCD


(21336m)

MVCD


(24384m)

MVCD


(27432m)

MVCD

feet (meters) 10000ft (3048m)

MVCD


(33528m)

765 800 806ft (246m)

889ft (271m)

917ft (280m)

945ft (288m)

973ft (297m)

1001ft (305m)

1029ft (314m)

1057ft (322m)

1085ft (331m)

1113ft (339m)

500 550 506ft (154m)

566ft (173m)

586ft (179m)

607ft (185m)

628ft (191m)

649ft (198m)

67ft (204m)

692ft (211m)

713ft (217m)

735ft (224m)

345 362 312ft (095m)

353ft (108m)

367ft (112m)

382ft (116m)

397ft (121m)

412ft (126m)

427ft (130m)

443ft (135m)

458ft (140m)

474ft (144m)

230 242 297ft (091m)

336ft (102m)

349ft (106m)

363ft (111m)

378ft (115m)

392ft (119m)

407ft (124m)

422ft (129m)

437ft (133m)

453ft (138m)

161 169 2ft (061m)

228ft (069m)

238ft (073m)

248ft (076m)

258ft (079m)

269ft (082m)

28ft (085m)

291ft (089m)

303ft (092m)

314ft (096m)

138 145 17ft (052m)

194ft (059m)

203ft (062m)

212ft (065m)

221ft (067m)

23ft (070m)

24ft (073m)

249ft (076m)

259ft (079m)

27ft (082m)

115 121 141ft (043m)

161ft (049m)

168ft (051m)

175ft (053m)

183ft (056m)

191ft (058m)

199ft (061m)

207ft (063m)

216ft (066m)

225ft (069m)

88 100 115ft (035m)

132ft (040m)

138ft (042m)

144ft (044m)

15ft (046m)

157ft (048m)

164ft (050m)

171ft (052m)

178ft (054m)

186ft (057m)

69 72 082ft (025m)

094ft (029m)

099ft (030m)

103ft (031m)

108ft (033m)

113ft (034m)

118ft (036m)

123ft (037m)

128ft (039m)

134ft (041m)

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)) mdashmdash MMiinniimmuumm VVeeggeettaattiioonn CClleeaarraannccee DDiissttaanncceess ((MMVVCCDD)) For Direct Current Voltages

( DC ) Nominal Pole

to Ground Voltage

(kV)

MVCD feet

(meters)

sea level

MVCD feet

(meters) 3000ft

(9144m) Alt

MVCD feet

(meters) 4000ft

(12192m) Alt

MVCD feet

(meters) 5000ft

(1524m) Alt

MVCD feet

(meters) 6000ft

(18288m) Alt

MVCD feet

(meters) 7000ft

(21336m) Alt

MVCD feet

(meters) (8000ft

(24384m) Alt

MVCD feet

(meters) 9000ft

(27432m) Alt

MVCD feet

(meters) 10000ft (3048m)

Alt

MVCD feet

(meters) 11000ft

(33528m) Alt

plusmn750 1392ft (424m)

1507ft (459m)

1545ft (471m)

1582ft (482m)

162ft (494m)

1655ft (504m)

169ft (515m)

1727ft (526m)

1762ft (537m)

1797ft (548m)

plusmn600 1007ft (307m)

1104ft (336m)

1135ft (346m)

1166ft (355m)

1198ft (365m)

123ft (375m)

1262ft (385m)

1292ft (394m)

1324ft (404m)

(1354ft 413m)

plusmn500 789ft (240m)

871ft (265m)

899ft (274m)

925ft (282m)

955ft (291m)

982ft (299m)

101ft (308m)

1038ft (316m)

1065ft (325m)

1092ft (333m)

plusmn400 478ft (146m)

535ft (163m)

555ft (169m)

575ft (175m)

595ft (181m)

615ft (187m)

636ft (194m)

657ft (200m)

677ft (206m)

698ft (213m)

plusmn250 343ft (105m)

402ft (123m)

402ft (123m)

418ft (127m)

434ft (132m)

45ft (137m)

466ft (142m)

483ft (147m)

5ft (152m)

517ft (158m)

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



bull avoid the problem associated with referring to tables in another standard (IEEE-516-2003) bull transmission lines operate in non-laboratory environments (wet conditions) bull 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 35 for voltages up to 362 kV phase to phase 30 for 500 - 550 kV phase to phase and 25 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 (ie 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 20 per unit This value is a conservative estimate of the transient over-voltage that is created at the point of application (eg a substation) by switching a capacitor bank without pre-insertion devices (eg closing resistors) At voltage levels where capacitor banks are not very common (eg 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 15 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 20 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 14 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 D5 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 ldquowetrdquo formulas are not vastly different when the same transient overvoltage factors are used the ldquowetrdquo 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 14 889 865 500 550 14 565 492 345 362 14 352 313 230 242 20 335 28 115 121 20 16 14

Table 5

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


765 800 20 1436 1395 500 550 24 110 1007 345 362 30 855 747 230 242 30 528 42 115 121 30 246 21





765 800 25 2025 204 500 550 30 1502 147 345 362 35 1042 944 230 242 35 632 514 115 121 35 290 245

PPrroojjeecctt 22001100--0077 GGeenneerraattoorr RReeqquuiirreemmeennttss aatt tthhee

TTrraannssmmiissssiioonn IInntteerrffaaccee

WWhhiittee PPaappeerr PPrrooppoossaall ffoorr IInnffoorrmmaall CCoommmmeenntt

March 2011

Project 2010-07 Generator Requirements at the Transmission Interface White Paper Proposal for Informal Comment March 2011 1

TTaabbllee ooff CCoonntteennttss Introduction 2

Objective 2

Proposed Next Steps and Review of Reliability Standards 4

Summary and Discussion of Other Solutions 7


Project 2010-07 Generator Requirements at the Transmission Interface White Paper Proposal for Informal Comment Introduction The Bulk Electric System1 consists of many parts including power plants and transmission facilities While most transmission facilities operate as part of the overall integrated grid a number of transmission facilities operate more like an extension cord to interconnect power plants and loads to the bulk power system2

These transmission facilities that connect power plants to the integrated grid are commonly known as generator interconnection facilities

Power plants and their respective pieces and parts come in all sizes and configurations Some plants consist of just a single generating unit other plants consist of multiple generating units and still others consist of multiple generating units spread over several thousand acres While not all power plants are considered part of the Bulk Electric System ultimately all the plants are interconnected to the bulk power system via their generator interconnection facilities Of concern is how to classify all such generating facilities including their generator interconnection facilities to determine what level of reliability is needed for such facilities Objective The purpose of Project 2010-07mdashGenerator Requirements at the Transmission Interface is to ensure that all generator-owned Facilities3

that are considered part of the Bulk Electric System are identified and that the level of reliability needed to operate such Facilities is appropriately covered under NERCrsquos Reliability Standards This will be accomplished by proposing a set of changes to existing standard requirements introducing new requirements and if necessary modifying definitions of some NERC-defined terms The collective efforts will add clarity to Generator Owners and Generator Operators regarding their reliability standard obligations at the interface with the integrated bulk power system

Since the formation of the Project 2010-07 Standard Drafting Team (SDT) in December 2010 the SDT has focused on reworking the Generator Requirements at the Transmission Interface Ad Hoc Grouprsquos4

1The current definition of ldquoBulk Electric Systemrdquo in the

(GOTO Ad Hoc Group) original proposed plan for addressing generator

NERCrsquos Glossary of Terms reads ldquoAs defined by the Regional Reliability Organization the electrical generation resources transmission lines interconnections with neighboring systems and associated equipment generally operated at voltages of 100 kV or higher Radial transmission facilities serving only load with one transmission source are generally not included in this definitionrdquo This definition is undergoing significant revision under Project 2010-17mdashDefinition of Bulk Electric System 2 This paper uses the term ldquobulk power systemrdquo as it is defined in Section 215 of the Federal Power Act ldquo(A) facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof) and (B) electric energy from generation facilities needed to maintain transmission system reliability The term does not include facilities used in the local distribution of electric energyrdquo 3 ldquoFacilityrdquo is defined in NERCrsquos Glossary of Terms as ldquoA set of electrical equipment that operates as a single Bulk Electric System Element (eg a line a generator a shunt compensator transformer etc)rdquo 4 NERC formed the Generator Requirements at the Transmission Interface Ad Hoc Group in 2009 to analyze and make recommendations for establishing general criteria for determining whether Generator Owners and Generator Operators should be registered for Transmission Owner and Transmission Operator requirements in NERCrsquos Reliability Standards


requirements at the transmission interface Based on feedback from the industry along with input from NERC and FERC staffs the GOTO Ad Hoc Group made a series of recommendations that included changes to various reliability standards the modification of existing definitions and the creation of some new definitions However based on more recent feedback from industry and regulators and after taking into account other standards projects under development the SDT decided that the plan of proposing new definitions modifying other definitions and making changes to dozens of standards was no longer necessary The SDT believes it is appropriate to classify various generating Facilities and Elements (including generator interconnection facilities) as part of the Bulk Electric System The SDT also believes that qualifying generator interconnection facilities should be classified as transmission That does not mean however that a Generator Owner or Generator Operator should be required to automatically register as a Transmission Owner or Transmission Operator simply because it owns andor operates transmission Elements or Facilities While qualifying Generator Owners and Generator Operators can be classified as owning and operating electric transmission Elements and Facilities these are most often not part of the integrated bulk power system and as such should not be subject to the same level of standards applicable to Transmission Owners and Transmission Operators who own and operate transmission Facilities and Elements that are part of the integrated bulk power system Requiring any classification that subjects Generator Owners and Generator Operators to all the standards applicable to Transmission Owners and Transmission Operators would do little if anything to improve the reliability of the Bulk Electric System When the transmission Elements and Facilities owned and operated by Generator Owners and Generator Operators are non-networknon-integrated transmission applying all standards applicable to Transmission Owners and Transmission Operators would have little effect on the overall reliability of the Bulk Electric System when compared to the operation of the equipment that actually produces electricity ndash the generation equipment itself To maintain an adequate level of reliability in the Bulk Electric System a clear delineation of responsibilities and authority at the interface between Generator OwnersOperators and Transmission OwnersOperators is needed This can be accomplished by properly applying selected standards or specific standard requirements to Generator Owners and Generator Operators The SDT is recommending a plan to modify the Purpose the Functional Entity section requirements and measures of a selected group of standards to make them applicable to Generator Owners and Generator Operators and to add clarity to such standards regarding generator interconnection facilities Note that at this stage in its work the SDT has made no final decisions on its proposed plan rather it is seeking informal feedback from the industry regarding its assumptions and recommendations Throughout the informal comment stage the SDT plans to rely heavily on this informal input and feedback to lessen the need to expend limited industry resources on developing specific and exacting standards changes At this informal stage the SDT has not developed definitional changes VSLs VRFs Implementation Plans etc for its proposed changes those will be developed as needed once the project progresses further and proposed changes are finalized


Proposed Next Steps and Review of Reliability Standards The Project 2010-07 Standard Drafting Team (SDT) proposes the following recommendations to clearly identify the appropriate generation Facilities and the standards requirements that should apply to such generation Facilities to ensure that the reliability of the Bulk Electric System is maintained

1 Add ldquoGenerator Ownerrdquo to the Applicability section of FAC-001-0 and add a requirement and a measure to address the responsibilities specific to the Generator Owner FAC-001-0mdashFacility Connection Requirements currently applies to Transmission Owners and addresses the need for Transmission Owners to establish facility connection and performance requirements While the standard requires Transmission Owners to address connection requirements for ldquogeneration facilities transmission facilities and end-user facilitiesrdquo it does not address the requirements for a Generator Owner that has received a request for interconnection The lack of such requirements for a Generator Ownerrsquos Facility could result in gaps Therefore the SDT proposes that ldquoGenerator Ownerrdquo be added to the Applicability section of FAC-001-0 It further proposes the addition of Requirement 4 and a corresponding measure


M4 The Generator Owner that receives an interconnection request for its facility

shall make available (to its Compliance Monitor) for inspection evidence that it met the requirements stated in Reliability Standard FAC-001-0 R4

These proposed standard changes are redlined in Attachment 1 Note that FAC-001-0 has been assigned for modification under Project 2010-02 but as of March 4 2011 no activity has yet taken place on that project

2 Add ldquoGenerator Ownerrdquo to the Applicability section of FAC-003-2 and modify the

requirements and measures to include Generator Owner

The proposed FAC-003-2 currently applies to Transmission Owners and addresses the need 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 A Transmission Vegetation Management Plan is used to ensure the reliable operation of electric transmission systems and prevent vegetation-related outages Because generator-owned Facilities may include electric transmission FAC-003-2 should be applicable to


Generator Owners Requiring Generator Owners to adhere to the requirements in this standard will ensure that Facilities like the generator interconnecting line lead are inspected as defined in the Transmission Vegetation Management Plan and that all vegetation that breaches specified clearances is properly trimmed This change in applicability will also ensure the proper reporting of vegetation-related outages to the appropriate Regional Reliability Organizations

The SDT proposes that ldquoGenerator Ownerrdquo is added to all requirements and measures that mention the Transmission Owner These proposed changes are outlined in Attachment 2 The SDT recognizes that if these standard changes are made changes to the accompanying FAC-003-2 definition modifications may also be needed As noted above such changes will be considered after informal comments are received

3 Follow the Project 2010-17mdashDefinition of Bulk Electric System and ensure that the

responsibility for generator interconnecting line leads is appropriately and clearly assigned to Generator Owners and Operators

The Project 2010-07 SDT recognizes that it cannot control the work of the SDT working on the definition of Bulk Electric System Still the Project 2010-07 SDT is hopeful that changes made to this definition will be instrumental in covering the reliability gap with respect to generator requirements at the transmission interface At this stage in the definitionrsquos development Project 2010-17rsquos concept paper has a section on Proposed BES Criteria and it includes the following

3 Generation plants (including GSU transformers and the associated generator interconnecting line lead(s)) with aggregate capacity greater than 75 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above

The Project 2010-07 SDT recognizes that this concept paper is a working draft and is in no way enforceable at this time still the Project 2010-07 SDT is hopeful that the BES team is moving in a direction that will be complementary to its own work

The proposed changes listed above mark a significant decrease in changes originally proposed by the GOTO Ad Hoc Group in its Final Report In particular clarifications to the definition of Bulk Electric System eliminate the need for the GOTO Ad Hoc Grouprsquos suggestions to include a reference to the proposed new term ldquoGenerator Interconnection Facilityrdquo in the following standards referenced in the GOTO Ad Hoc Group Final Report

bull BAL-005-01b bull CIP-002-1 bull EOP-001-0 bull EOP-004-1 bull FAC-008-1 bull FAC-009-1


bull IRO-005-2 bull MOD-010-0 bull MOD-012-0 bull PRC-004-1 bull PRC-005-1 bull TOP-002-2 bull TOP-003-0 bull VAR-001-1 bull VAR-002-1

All of the standards listed above already apply to the Generator Owner or Generator Operator5

so as long as generator-owned Facilities like generator interconnection facilities are appropriately assigned to the responsibility of those entities with changes to the definition of Bulk Electric System there should be no need to highlight the inclusion of ldquoGenerator Interconnection Facilityrdquo with language changes in those standards

Other proposed changes are also unnecessary In EOP-003-1 the GOTO Ad Hoc Group had originally proposed that Generator Operators be added to the requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic load-shedding throughout their areas The SDT determined that this addition was unnecessary because PRC-001 already includes the requirement that Transmission Operators coordinate their UFLS programs with underfrequency isolation of generating units which infers that Generator Operators need to provide their underfrequency settings to their respective Transmission Operator Further Generator Operators should not be involved in the high-level coordination that this standard requires In EOP-008-0 the proposed reference to the Generator Interconnection Operational Interface can be eliminated because the proposed term was meant to consist of Elements and Facilities rated at 100 kV and above which the team has acknowledged are transmission In the cases of PER-001-0 and PER-002-0 the SDT believes that additional requirements for training of Generator Owner and Generator Operator personnel should be addressed in a future project In FERC Order 693 a directive applied ldquoto generator operator personnel at a centrally-located dispatch center who receive direction and then develop specific dispatch instructions for plant operators under their controlrdquo FERC directed that those Generator Operator personnel receive formal training of the nature provided to system operators under PER-005-1 FERC Order 742 confirms that the Commission has ldquonot modified the scope of applicability of the Order 693 directive regarding generator operator trainingrdquo

The SDT has also considered proposing further modifications to PRC-001-2 to ensure coordination of protection system information among Generator Operators and Transmission Operators and to standards TOP-001-2 and TOP-003-2 (all of which are currently under development) to ensure that coordination of information among Generator Operators and Transmission Operators The SDT has consulted with the members of the Project 2007-03mdash

5 Many have also changed significantly since the GOTO Ad Hoc Grouprsquos review


Real-time Operations SDT and believes that the necessary level of coordination (including for Special Protection Systems) is covered by the requirements in the proposed new TOP-003-2 In TOP-004-2 the GOTO Ad Hoc Grouprsquos addition of R7 (requiring the Generator Operator to operate its generator interconnection facility within its applicable ratings) is not needed because existing TOP and IRO standards require entities to operate within or to mitigate SOLs and IROLs at the direction of the TOP and RC The proposed addition of R5 to TOP-008-1 is also unnecessary because it will be covered in the data specifications of TOP-003-2 R1 (TOP-008 is being retired) Summary and Discussion of Other Solutions Again the purpose of this project is to clearly identify the appropriate generation Facilities and the standards requirements that should apply to such generation Facilities to ensure that the reliability of the Bulk Electric System is maintained The SDT recognizes that its work alone may not eliminate all reliability gaps with respect to generator-owned Facilities like generator interconnection facilities As noted above Project 2010-17mdashDefinition of Bulk Electric System may have an enormous impact on the work of this SDT We are confident that these changes we have proposed to a small number of standards in coordination with changes to the Bulk Electric System definition can achieve the necessary reliability but we also acknowledge that many entities have taken advantage of solutions outside the standards process that have achieved the same effect On April 20 2010 NERC Compliance published a Public Bulletin to provide guidance for situations like this in which entities delegate reliability tasks to a third-party entity In this bulletin NERC Compliance emphasizes that while a registered entity may not delegate its responsibility for ensuring that a task is completed it may delegate the performance of a task to another entity As is explained in the bulletin compliance responsibility for applicable NERC Reliability Standard requirements and accountability for violations thereof may be achieved through several means including the following

1 By Individual an entity is registered on the NERC Compliance Registry and such registered entity assumes full compliance responsibility and accountability or

2 By Written Contract parties enter into written agreement whereby

a A registered entity delegates the performance of some or all functional activities to a third party that is not a registered entity and the registered entity retains full compliance responsibility and violation accountability or

b A registered entity delegates the performance of some or all of the functional activities to a third party and the third party accepts full compliance responsibility for the specific functions it performs and violation accountability In this case there may be individual concurrent or joint registration of the entities depending on the nature of the contractual relationship and in any event only the registered entity would be held responsible or accountable by a Regional Entity or NERC or


3 By Joint Registration Organization (JRO) each party is registered and is required to clearly identify and allocate compliance responsibility and violation accountability for their respective functions under applicable NERC Reliability Standard requirements

Because the standards efforts outlined here will not take effect for a year or more Generator Owners and Generator Operators that are concerned about their registration status should explore options like those explained above and in further detail in NERC Compliance Bulletin 2010-004 The Project 2010-07 SDT will continue with the efforts outlined above but will modify its proposal and ultimate actions based on feedback from the industry

Standards Announcement

Project 2010-07 Generator Requirements at the Transmission Interface Informal Comment Period Open March 4 ndash April 4 2011 Now available at httpwwwnerccomfilezstandardsProject2010-07_GOTO_Projecthtml Informal Comment Period Open through 8 pm Eastern on Monday April 4 2011 The Project 2010-07 Generator Requirements at the Transmission Interface drafting team has posted for a 30-day informal comment period a White Paper on proposed concepts to support the modifications of various standards to clarify the reliability standard responsibilities of Generator Owners and Generator Operators at the interface to the interconnected grid The White Paper along with proposed redlined changes to standards that would be affected by the proposal have been posted on the project Web page at httpwwwnerccomfilezstandardsProject2010-07_GOTO_Projecthtml Instructions The drafting team welcomes any constructive feedback for improving its proposal to ensure that the responsibilities of Generator Owners and Generator Operators at the interface to the interconnected grid are covered under NERCrsquos Reliability Standards Consider using the following questions to focus your comments

bull How can the proposal outlined in the White Paper be improved Is the drafting team heading in the right direction

bull The drafting team has chosen to use informal means of receiving industry feedback (webinars presentations before industry stakeholder groups etc) prior to expending valuable industry resources to develop specific proposals for reliability standard requirements measures VSLs etc Do you have any further suggestions for seeking industry input before the project moves into a more formal development phase

bull The Ad Hoc group originally proposed the new terms ldquoGenerator Interconnection Facilityrdquo and ldquoGenerator Interconnection Operational Interfacerdquo as part of this project The Project 2010-07 drafting team believes that changes to the definition of Bulk Electric System under Project 2010-17 and modifications to a select group of standards can accomplish the same goal without the need for new definitions Do you support this approach If not please explain

Please submit comments by e-mail to Mallory Huggins at malloryhugginsnercnet Next Steps The drafting team will consider the input received on the concept White Paper as it continues its work

Project Background Significant industry concern exists regarding the application of Transmission Owner and Transmission Operator requirements and more specifically 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 NERC formed the Generator Requirements at the Transmission Interface Ad Hoc Group in 2009 to analyze and make recommendations for establishing general criteria for determining whether Generator Owners and Generator Operators should be registered for Transmission Owner and Transmission Operator requirements in NERCrsquos Reliability Standards The Ad Hoc Group developed a report evaluating the issues and proposing a number of changes to add clarity on the requirements for generator interconnection facilities Using feedback from the industry NERC and FERC the Project 2010-07 drafting team significantly revised the Ad Hoc Grouprsquos original proposal and offers a refined proposal here Standards Process The Standard Processes Manual contains all the procedures governing the standards development process The success of the NERC standards development process depends on stakeholder participation We extend our thanks to all those who participate

For more information or assistance please contact Monica Benson Standards Process Administrator at monicabensonnercnet or at 404-446-2560

North American Electric Reliability Corporation 116-390 Village Blvd Princeton NJ 08540


EOP-004-2 mdash Impact Event and Disturbance Assessment Analysis and Reporting

Draft 1 September 10 20102 March 7 2011 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 (April 2009)

2 SAR posted for comment (April 22 ndash May 21 2009)

3 SC authorized moving the SAR forward to standard development (September 2009)

4 Concepts Paper posted for comment (March 17 ndash April 16 2010)

5 Initial Informal Comment Period (September 2010)

Proposed Action Plan and Description of Current Draft This is the first posting of the proposed standard in accordance with Results-Based Criteria The drafting team requests posting for a 30-day formal comment period Future Development Plan

Anticipated Actions Anticipated Date Initial Comment PeriodDrafting team considers comments makes conforming changes and proceed to second comment

SeptemberOctober 2010 ndash February 2011

Drafting team considers comments makes conforming changes and proceed to second comment Second Comment Period

October ndash December 2010March ndash May 2011

Third Comment PeriodInitial Ballot period December 2010- JanuaryJune- July 2011

Successive CommentRecirculation Ballot period February ndash MarchJuly-August 2011

Receive BOT approval AprilSeptember 2011



EEffffeeccttiivvee DDaatteess 1 USA The standard shall become effective on the Ffirst calendar day of the ffiirrssttthird calendar quarter oonnee yyeeaarr after the date of the order providing applicable regulatory authority approval for all requirements 2 Canada and Mexico FFiirrsstt ccaalleennddaarr ddaayy ooffConcurrent with the ffiirrsstt ccaalleennddaarr qquuaarrtteerr oonnee yyeeaarr ffoolllloowwiinngg BBooaarrdd ooff TTrruusstteeeess aaddooppttiioonn uunnlleessss ggoovveerrnnmmeennttaall aauutthhoorriittyy wwiitthhhhoollddss aapppprroovvaallEffective Date for the USA In those jurisdictions where no regulatory approval is required the standard shall become effective on the first calendar day of the third calendar quarter after Board of Trustees adoption VVeerrssiioonn HHiissttoorryy Version Date Action Change Tracking

2 Merged CIP-001-1 Sabotage Reporting and EOP-004-1 Disturbance Reporting into EOP-004-2 Impact Event Reporting Retire CIP-001-1a Sabotage Reporting and Retired EOP-004-1 R1 R32 R33 R34 R4 R5 and associated measures evidence retention and VSLs Disturbance Reporting Added new requirements for ERO ndash R1 R7 R8

Revision to entire standard (Project 2009-01)





Formatted Normal



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 None Impact Event Any event which has either impacted or has the potential to impact the reliability of the Bulk Electric System Such events may be caused by equipment failure or mis-operation environmental conditions or human action



When this standard has received ballot approval the text boxes will be moved to the Guideline and Technical Basis Section

Introduction

1 Title Impact Event and Disturbance Assessment Analysis and Reporting 2 Number EOP-004-2 3 Purpose Responsible Entities shall report impact events and their known causes to

support situationalTo improve industry awareness and the reliability of the Bulk Electric System (BES)by requiring the reporting of Impact Events and their causes if known by the Responsible Entities

4 Applicability 41 Functional Entities Within the context of EOP-004-2 the term ldquoResponsible

Entityrdquo shall mean 411 Reliability Coordinator 412 Balancing Authority 413 Interchange Authority 414 Transmission Service Provider 413415 Transmission Owner 414416 Transmission Operator 415417 Generator Owner 416418 Generator Operator 417419 Distribution Provider 418 Electric Reliability Organization 4110 Load Serving Entity

5 Background NERC established a SAR Team in 2009 to investigate revisions to the CIP-001 and EOP-004 Reliability Standards

1 CIP-001 may be merged with EOP-004 to eliminate redundancies 2 Acts of sabotage have to be reported to the DOE as part of EOP-004 3 Specific references to the DOE form need to be eliminated 4 EOP-004 has some lsquofill-in-the-blankrsquo components to eliminate

The development may include other improvements to the standards deemed appropriate by the drafting team with the consensus of stakeholders consistent with establishing high quality



enforceable and technically sufficient bulk power system reliability standards (see tables for each standard at the end of this SAR for more detailed information) The SAR for Project 2009-01 Disturbance and Sabotage Reporting was moved forward for standard drafting by the NERC SC in August of 2009 The Disturbance and Sabotage Reporting Standard Drafting Team (DSR SDT) was formed in late 2009 A ldquoconcepts paperrdquo was designed to solicit stakeholder input regarding the proposed reporting concepts that the DSR SDT has developed The concept paper sought comments from stakeholders on the ldquoroad maprdquo that will be used by the SDR SDT in updating or revising CIP-001 and EOP-004 The concept paper provided stakeholders the background information and thought process of the SDR SDT The DSR SDT has reviewed the existing standards the SAR issues from the NERC database and FERC Order 693 Directives in order to determine a prudent course of action with respect to these standards The DSR SDT has proposed the following concept for impact eventused a working definition for ldquoImpact Eventsrdquo to develop Attachment 1 as follows

ldquoAn impact eventImpact Event is any event that has either impacted or has the potential to impact the reliability of the Bulk Electric System Such events may be caused by equipment failure or mis-operation environmental conditions or human actionrdquo

The DSR SDT has proposed this definition for inclusion in the NERC Glossary for ldquoImpact Eventrdquo The types of Impact Events that are required to be reported are contained within Attachment 1 Only these events are required to be reported under this Standard The DSR SDT considered the FERC directive to ldquofurther define sabotagerdquo and decided to eliminate the term sabotage from the standard The team felt that it was almost impossible to determine if an act or event was that of sabotage or merely vandalism without the intervention of law enforcement after the fact This will result in further ambiguity with respect to reporting events The term ldquosabotagerdquo is no longer included in the standard and therefore it is inappropriate to attempt to define it The Impact Events listed in Attachment 1 provide guidance for reporting both actual events as well as events which may have an impact on the Bulk Electric System The DSR SDT believes that this is an equally effective and efficient means of addressing the FERC Directive Attachment 1 Part A is to be used for those actions that have impacted the electric system and in particular the section ldquoDamage or destruction to equipmentrdquo clearly defines that all equipment that intentional or non intentional human error be reported Attachment 1 Part B covers the similar items but the action has not fully occurred but may cause a risk to the electric system and is required to be reported To support this concept the DSR SDT has provided specific event for reporting including types of impact eventsImpact Events and timing thresholds pertaining to the different types of impact eventsImpact Events and whorsquos responsibility for reporting under the different impact eventsImpact Events This information is outlined in Attachment 1 to the proposed standard



The DSR SDT wishes to make clear that the proposed changes do not include any real-time operating notifications for the types of events covered by CIP-001 EOP-004 This is achieved through the RCIS and is covered in other standards (eg TOP) The proposed standard deals exclusively with after-the-fact reporting The DSR SDT is proposing to consolidate disturbance and impact eventImpact Event reporting under a single standard These two components and other key concepts are discussed in the following sections Summary of Concepts

bull A single form to report disturbances and impact eventsImpact Events that threaten the reliability of the bulk electric system

bull Other opportunities for efficiency such as development of an electronic form and possible inclusion of regional reporting requirements

bull Clear criteria for reporting bull Consistent reporting timelines bull Clarity around of who will

receive the information and how it will be used

Law Enforcement Reporting The reliability objective of EOP-004-2 is to prevent outages which could lead to Cascading by effectively reporting Impact Events Certain outages such as those due to vandalism and terrorism are not preventable Entities rely upon law enforcement agencies to respond and investigate those Impact Events which have the potential of wider area affect upon the industry which enables and supports reliability principles such as protection of bulk power systems from malicious physical or cyber attack The Standard is intended to reduce the risk of Cascading involving Impact Events The importance of BES awareness of the threat around them is essential to the effective operation and planning to mitigate the potential risk to the BES Stakeholders in the Reporting Process

bull Industry

Rationale for R1 The goal of the DSR SDT is to have a generic reporting form and a system for all functional entities (US Canada Mexico) to submit impact event reports to NERC and other entities Ultimately it may make sense to develop an electronic version of the form to expedite completion sharing and storage Ideally entities would complete a single electronic form on-line which could then be electronically forwarded or distributed to jurisdictional agencies and functional entities as appropriate using check boxes or other coding within the electronic form Specific reporting forms that exist today (ie - OE-417 etc) could be included as part of the electronic form to accommodate US entities with a requirement to submit the form or may be removed (but still be mandatory for US entities under Public Law 93-275) to streamline the proposed consolidated reliability standard for all North American entities (US Canada Mexico) Jurisdictional agencies may include DHS FBI NERC RE FERC Provincial Regulators and DOE Functional entities may include the RC TOP and BA for situational awareness Applicability of the standard will be determined based on the specific requirements The DSR SDT recognizes that some regions require reporting of additional information beyond what is in EOP-004 The DSR SDT is planning to update the listing of reportable events from discussions with jurisdictional agencies NERC Regional Entities and stakeholder input There is a possibility that regional differences may still exist Responsible entities will ultimately be responsible for ensuring that OE-417 reports are received at the DOE



bull NERC (ERO) bull FERC bull DOE bull DHS ndash Federal bull Homeland Security- State bull State Regulators bull Local Law Enforcement bull State Law Enforcement bull FBI

The above stakeholders have an interest in the timely notification communication and response to an incident at an industry facility The stakeholders have various levels of accountability and have a vested interest in the protection and response to ensure the reliability of the BES Present expectations of the industry under CIP-001 It has been the understanding by industry participants that an occurrence of sabotage has to be reported to the FBI The FBI has the jurisdictional requirements to investigate acts of sabotage and terrorism The present CIP-001-1 standard requires a liaison relationship on behalf of the industry and FBI Annual requirements under the standard of the industry have not been clear and have lead to misunderstandings and confusion in the industry as to how to demonstrate the liaison is in place and effective FBI offices have been asked to confirm on FBI letterhead the existence of a working relationship to report acts of sabotage to include references to years the liaison has been in existence and confirming telephone numbers for the FBI Coordination of Local and State Law Enforcement Agencies with the FBI The Joint Terrorism Task Force (JTTF) came into being with the first task force being established in 1980 JTTFs are small cells of highly trained locally based passionately committed investigators analysts linguists SWAT experts and other specialists from dozens of US law enforcement and intelligence agencies The JTTF is a multi-agency effort led by the Justice Department and FBI designed to combine the resources of federal state and local law enforcement Coordination and communications largely through the interagency National Joint Terrorism Task Force working out of FBI Headquarters which makes sure that information and intelligence flows freely among the local JTTFs This information flow can be most beneficial to the industry in analytical intelligence incident response and investigation Historically the most immediate response to an industry incident has been local and state law enforcement agencies to suspected vandalism and criminal damages at industry facilities Relying upon the JTTF coordination between local state and FBI law enforcement would be beneficial to effective communications and the appropriate level of investigative response Coordination of Local and Provincial Law Enforcement Agencies with the RCMP A similar law enforecment coordination hierarchy exists in Canada Local and Provincial law enforcement coordinate to investigate suspected acts of vandalism and sabotage The Provincial



law enforcement agency has a reporting relationship with the Royla Canadian Mounted Police (RCMP) A Reporting Process Solution ndash EOP-004 A proposal discussed with FBI FERC Staff NERC Standards Project Coordinator and SDT Chair is reflected in the flowchart below (Reporting Hierarchy for Impact Event EOP-004-2) Essentially reporting an Impact Event to law enforcement agencies will only require the industry to notify the state or provincial level law enforcement agency The state or provincial level law enforcement agency will coordinate with local law enforcement to investigate If the state or provincial level law enforcement agency decides federal agency law enforcement or the RCMP should respond and investigate the state or provincial level law enforcement agency will notify and coordinate with the FBI or the RCMP



Entity Experiencing an Actual Impact Event from Attachment 1

Report to Law Enforcement

YESNO

Refer to Ops Plan for Reporting procedures

Notification Protocol to State Agency Law

Enforcement

Report Impact Event to NERC Regional Entity

State Agency Law Enforcement coordinates as appropriate with FBI

State Agency Law Enforcement notifies FBI

NERC and Regional Entities conduct

investigation

NERCEvents Analysis

Confirmed Sabotage

YESNO

Reporting Hierachy for Impact Event EOP-004-2

FBI Responds and makes notification

to DHS

File DOE Form 417 with Dept of Energy

Procedure to Report to

NERC

Procedure to Report to Law Enforcement

Report Impact Event to NERC Regional

Entity


investigation


State Agency Law Enforcement Investigates


Canadian entities will follow law enforcement protocols applicable in their jurisdictions

NERC Reports Applicable Events to FERC Per Rules

of Procedure NERC Reports Applicable Events to FERC Per Rules of

Procedure



Requirements and Measures R1 The ERO shall establish maintain and utilize a

system for receiving and distributing impact event reports received pursuant to Requirement R6 to applicable government provincial or law enforcement agencies and Registered Entities to enhance and support situational awareness

M1 The ERO shall provide evidence that it established maintained and utilized a system for the distribution of the reports it receives to the various organizations or agencies Such evidence could include but is not limited to dated records indicating that reports were distributed as shown on the submitted report or electronic logs indicating distribution of reports (R1)

Rationale for R1 Every industry participant that owns or operates elements or devices on the grid has a formal or informal process procedure or steps it takes to gather information regarding what happened and why it happened when Impact Events occur This requirement has the Registered Entity establish documentation on how that procedure process or plan is organized For the Impact Event Operating Plan the DSR SDT envisions that Part 12 includes performing sufficient analysis and information gathering to be able to complete the report for reportable Impact Events The main issue is to make sure an entity can a) identify when an Impact Event has occurred and b) be able to gather enough information to complete the report Part 13 could include a process flowchart identification of internal positions to be notified and to make notifications or a list of personnel by name as well as telephone numbers The Impact Event Operating Plan may include but not be limited to the following how the entity is notified of eventrsquos occurrence person(s) initially tasked with the overseeing the assessment or analytical study investigatory steps typically taken and documentation of the assessment remedial action plan



R2 Each ApplicableResponsible Entity identified in Attachment 1 shall have an Impact Event Operating Plan(s) that includes [Violation Risk Factor Medium] [Time Horizon Long-term Planning]

11 An Operating Process for identifying assessing and reporting impact events Impact Events listed in Attachment 1 that includes

12 An Operating Procedure for gathering information for Attachment 2 regarding observed Impact Events listed in Attachment 1

1113 An Operating Process for communicating recognized Impact Events to the following components

12 Method(s) for identifying impact events

13 Method(s) for assessing cause(s) of impact events

14 Method(s) for making internal and external notifications pursuant to Parts 25 and 26

141131 List of internalInternal company personnel responsible for making initial notification(s) pursuant to Parts 25and 26)

15 List of internal company personnel to notify

151132 List of externalExternal organizations to notify to include but not limited to NERCthe Responsible Entitiesrsquo Reliability Coordinator NERC Responsible Entitiesrsquo Regional Entity Law Enforcement and Governmental or Provincial Agencies

1614 MethodProvision(s) for updating the Impact Event Operating Plan when there is a component change within 3090 days of the notification of theany change to its content

17 A provision for updating the Operating Plan based on lessons learned from an exercise or implementation of the Operating Plan within 30 days of identifying the lessons learned

18 A provision for updating the Operating Plan based on applicable lessons learned from the annual NERC report issued pursuant to Requirement R8 within 30 days of NERC publishing lessons learned

Rationale for R2 Every industry participant that owns or operates elements or devices on the grid has a formal or informal process procedure or steps it takes to assess what happened and why it happened when impact events occur This requirement has the Registered Entity establish documentation on how that procedure process or plan is organized For the Operating Plan the DSR SDT envisions that ldquoassessingrdquo includes performing sufficient analysis to be able to complete the report for reportable impact events The main issue is to make sure an entity can a) identify when an impact event has occurred and b) be able to gather enough information to complete the report Parts 33 and 34 include but not limited to operating personnel who could be involved with any aspect of the operating plan The Operating Plan may include but not be limited to the following how the entity is notified of eventrsquos occurrence person(s) initially tasked with the overseeing the assessment or analytical study investigatory steps typically taken and documentation of the assessment remedial action plan



M2 M1 Each ApplicableResponsible Entity shall provide the current in force Impact Event

Operating Plan to the Compliance Enforcement Authority upon request (R2)



R3

R2 Each ApplicableResponsible Entity shall identify and assess initial probable cause of impact events listed in Attachment 1 in accordance with itsimplement its Impact Event Operating Plan documented in Requirement R2R1 for Impact Events listed in Attachment 1 (Parts A and B) [Violation Risk Factor Medium] [Time Horizon Real-time Operations and Same-day Operations]

M3M2 To the extent that an ApplicableResponsible Entity has an impact eventImpact Event on its Facilities the ApplicableResponsible Entity shall provide documentation of its assessment or analysisthe implementation of its Impact Event Operating Plans Such evidence could include but is not limited to operator logs voice recordings or power flow analysis cases (R3)other notations and documents retained by the Registered Entity for each Impact Event

R4 R3 Each ApplicableResponsible Entity

shall conduct a drill exercise or Real-time implementationtest of its Operating PlanProcess for reportingcommunicating recognized Impact Events created pursuant to Requirement R2R1 Part 13 at least annually with no more than 15 calendar months between exercises ortests [Violation Risk Factor Medium] [Time Horizon Long-term Planning]

M3 In the absence of an actual use

Impact Event the Responsible Entity shall provide evidence that it conducted a mock Impact Event and followed its Operating Process for communicating recognized Impact Events created pursuant to Requirement R1 Part 13 The time period between actual and or mock Impact Events shall be no more than 15 months Evidence may include but is not limited to operator logs voice recordings or documentation (R3)

Rationale for R3 The DSR SDT intends for each Responsible Entity to verify that its Operating Process for communicating recognized Impact Events is correct so that the entity can respond appropriately in the case of an actual Impact Event The Responsible Entity may conduct a drill or exercise of its Operating Process for communicating recognized Impact Events as often as it desires but the time period between such drill or exercise can be no longer than 15 months from the previous drillexercise or actual Impact Event (ie if you conducted an exercisedrillactual employment of the Operating Process in January of one year there would be another exercisedrillactual employment by March 31 of the next calendar year)) Multiple exercises in a 15 month period are not a violation of the requirement and would be encouraged to improve reliability

Rationale for R3 The DSR SDT intends for each Applicable Entity to assess the causes of the reportable impact event and gather enough information to complete the report that is required to be filed

Rationale for R4 The DSR SDT intends for each Applicable Entity to conduct a drill or exercise of it Operating Plan as often as merited but no longer than 15 months from the previous exercise to prevent a long cycle of exercises (ie conducting an exercise in January of one year and then December of the next year) Multiple exercises in a 15 month period is not a violation of the requirement and would be encouraged to improve reliability A drill or exercise may be a table-top exercise a simulation or an actual implementation of the Operating Plan



M4 The ApplicableR4 Each Responsible Entity shall provide evidence that it conducted a

drill exercise or Real-time implementation of thereview its Impact Event Operating Plan for reporting as specified in the requirement Such evidence could include but is not limited to a dated exercise scenario with notes on the exercise or operator logs voice recordings or power flow analysis cases for an actual implementation of the Operating Plan (R4)



R5 Each Applicable Entity shall provide training to all internal those personnel who have responsibilities identified in its Operating Plan for reporting pursuant to Requirement R2 subject to the following

51 The training includes the personnel required to respond and their required actions under the Operating Plan

Training conductedthat plan at least once per calendar yearannually with no more than 15 calendar months between trainingreview sessions for personnel with existing responsibilities [Violation Risk Factor Medium] [Time Horizon Long-term Planning ]

52 If the Operating Plan is revised (with the exception of contact information revisions) training shall be conducted within 30 days of the Operating Plan revisions

53 For internal personnel added to the Operating Plan or those with revised responsibilities under the Operating Plan training shall be conducted prior to assuming the responsibilities in the plan

M5 Applicable

M4 Responsible Entities shall provide the actual training materialmaterials presented to verify content and the association between the people listed in the plan and those who participated in the trainingreview documentation showing who was trainedpresent and when internal personnel were trained on the responsibilities in the Operating Plan as well as dates for personnel changes and evidence that the training was conducted following personnel changes (R5)plan

R6R5 Each ApplicableResponsible Entity shall report impact eventsImpact Events in

accordance with itsthe Impact Event Operating Plan created pursuant to Requirement R2R1 and Attachment 1 using the timelines outlinedform in Attachment 12 or the DOE OE-417 reporting form [Violation Risk Factor Medium] [Time Horizon Real-time Operations and Same-day Operations]

M6 RegisteredM5 Responsible Entities shall provide evidence demonstrating the submission of reports using the Operating Planplan created pursuant to Requirement R2 for impact eventsR1 and Attachment 1 using either the form in Attachment 2 or the DOE OE-417 report Such evidence will include a copy of the original impact eventAttachment 2 form or OE-417 report submitted evidence to support the type of impact eventImpact Event

Rationale for R5 The SDT is not prescribing how training is to be conducted and leaves that decision to each Applicable Entity as they best know how to conduct such activities Conduct of an exercise constitutes training for compliance with this requirement For changes to the Operating Plan (53) the training may simply consist of a review of the revised responsibilities and a ldquosign-offrdquo that personnel have reviewed the revisions



experienced the date and time of the impact event Impact Event as well as evidence of report submittal that includes date and time (R6)



R7 The ERO shall annually review and propose revisions to the impact event table (Attachment 1) if warranted based on its analysis of reported impact events Revisions to Attachment 1 shall follow the Reliability Standards Development Procedure

M7 The ERO shall provide evidence that it reviewed the impact event table If applicable the ERO shall provide evidence that it followed the Reliability Standards Development Procedure to propose and implement revisions to Attachment 1 Such evidence may include but not be limited to documentation that compares or assesses the list of impact events (Attachment 1) against the analysis of reported impact events (R7)

R8 The ERO shall publish a quarterly report

of the yearrsquos reportable impact events subject to the following

81 Issued no later than 30 days following the end of the calendar quarter

82 Identifies trends on the BES

83 Identifies threats to the BES

84 Identifies other vulnerabilities to the BES

85 Documents lessons learned

86 Includes recommended actions

M8 The ERO shall provide evidence that it issued a report identifying trends threats or other

vulnerabilities on the bulk electric system at least quarterly Such evidence will include a copy of the report as well as dated evidence of the reportrsquos issuance (R8)

CCoommpplliiaannccee


Rationale for R8 The ERO will analyze Impact Events that are reported through requirement R6 The DSR SDT envisions the ERO issuing reports identifying trends threats or other vulnerabilities when available or at least quarterly The report will include lessons learned and recommended actions (such as mitigation plans) to improve reliability as applicable

Rationale for R7-R8 Some of the concepts contained in Requirements R7 and R8 are contained in the NERC Rules of Procedure section 800 The DSR SDT felt that in order to have a complete standard for reporting impact events that improved reliability there needed to be feedback to industry on a regular basis as well as when issues are discovered The analysis of impact events is crucial and the subsequent dissemination of the results of that analysis must be performed In accordance with Sections 401(2) and 405 of the Rules of Procedures the ERO can be set as an applicable entity in a requirement or standard After careful consideration the DSR SDT believes that these requirements (R7-8) are best applicable to the ERO



bull Regional Entity or

bull For requirements applicable to the ERO an entity contracted to perform an audit

bull If the Responsible Entity works for the Regional Entity then the Regional Entity will establish an agreement with the ERO or another entity approved by the ERO and FERC (ie another Regional Entity) to be responsible for compliance enforcement


bull Compliance Audits bull Self-Certifications bull Spot Checking bull Compliance Violation Investigations bull Self-Reporting bull Complaints

Evidence Retention Each Reliability Coordinator Balancing Authority Transmission Owner Transmission Operator Generator Owner Generator Operator and Distribution ProviderResponsible Entity shall keepretain data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation

The ERO shall retain evidence of Requirements 1 7 and 8 Measures 1 7 and 8 for three calendar years

Each Reliability Coordinator Balancing Authority Transmission Owner Transmission Operator Generator Owner Generator Operator and Distribution Provider shall retain data or evidence of Requirements 2 3 4 and 5 and Measures 2 3 4 and 5 for three calendar years for the duration of any regional or Compliance Enforcement Authority investigation whichever is longer 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

Each Reliability Coordinator Balancing Authority Transmission Owner Transmission Operator Generator Owner Generator Operator and Distribution Provider shall retain data or evidence of Requirement 6 and Measure 6 for three calendar years for the duration of any regional investigation whichever is longer 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

If a Registered Entity is found non-compliant it shall keep information related to the non-compliance until found compliant or for the duration specified above whichever is longer




Additional Compliance Information To be determined

None

Table of Compliance Elements

R Time Horizon

VRF Violation Severity Levels

Lower VSL Moderate VSL High VSL Severe VSL

R1 Long-term Planning

Medium The Responsible Entity has an Impact Event Operating Plan but failed to include one of Parts 11 through 14

The Responsible Entity has a Impact Event Operating Plan but failed to include two of Parts 11 through 14

The Responsible Entity has an Impact Event Operating Plan but failed to include three of Parts 11 through 14

The Responsible Entity failed to include all of Parts 11 through 14

R2 Real-time Operations and Same-day Operations

Medium NA NA NA The Responsible Entity failed to implement its Impact Event Operating Plan for an Impact Event listed in Attachment 1


Medium The Responsible Entity failed to conduct a test of its Operating Process for communicating recognized Impact Events created pursuant to

The Responsible Entity failed to conduct a test of its Operating Process for communicating recognized Impact Events created pursuant to





Requirement R1 Part 13 in more than 15 months but less than 18 months

Requirement R1 Part 13in more than 18 months but less than 21 months


Requirement R1 Part 13 in more than 24 months


Medium The Responsible Entity failed to review its Impact Event Operating Plan with those personnel who have responsibilities identified in that plan l in more than 15 months but less than 18 months

The Responsible Entity failed to review its Impact Event Operating Plan with those personnel who have responsibilities identified in that plan in more than 18 months but less than 21 months


The Responsible Entity failed to review its Impact Event Operating Plan with those personnel who have responsibilities identified in that plan in more than 24 months


Medium The Responsible Entity failed to submit a report in less than 36 hours for an Impact Event requiring reporting within 24 hours in Attachment 1

The Responsible Entity failed to submit a report in more than 36 hours but less than or equal to 48 hours for an Impact Event requiring reporting within 24 hours in Attachment 1


OR

The Responsible Entity failed to submit a report in more than 1 hour but less than 2 hours for an Impact Event requiring reporting within 1 hour

The Responsible Entity failed to submit a report in more than 60 hours for an Impact Event requiring reporting within 24 hours in Attachment 1

OR

The Responsible Entity failed to submit a report in more than 2 hours for an Impact Event requiring reporting within 1 hour in Attachment 1

OR

The responsible entity



in Attachment 1 failed to submit a report for an Impact Event in Attachment 1

VVaarriiaanncceess

None IInntteerrpprreettaattiioonnss

None



EEOOPP--000044 -- AAttttaacchhmmeenntt 11 IImmppaacctt EEvveennttss TTaabbllee NOTE Under certain adverse conditions eg severe weather it may not be possible to assessreport the damage caused by an impact eventImpact Event and issue a written Impact Event Report within the timing in the table below In such cases the affected ApplicableResponsible Entity shall notify its Regional Entity(ies) and NERC and verbally (e-mail esisacnerccom Facsimile 609-452-9550 Voice 609-452-1422) and provide as much information as is available at that time The affected ApplicableResponsible Entity shall then provide periodic verbal updates until adequate information is available to issue a written Preliminary Impact Event Reportreport

EOP-004 ndash Attachment 1 - Actual Reliability Impact ndash Part A

Event Entity with Reporting Responsibility

Threshold for Reporting Time to Submit Report

Energy Emergency requiring Public appeal for load reduction

RC BAInitiating entity is responsible for reporting

To reduce consumption in order to maintain the continuity of the BES Each public appeal for load reduction

Within 1 hour of issuing a public appeal

Energy Emergency requiring system-wide voltage reduction

RC TO TOP DP Initiating entity is responsible for reporting

System wide voltage reduction of 3 or more Within 1 hour after occurrenceevent is identifiedinitiated

Energy Emergency requiring manual firm load shedding

Initiating entity is responsible for reporting

Manual firm load shedding ge 100 MW Within 1 hour after event is initiated

Energy Emergency requiringresulting in automatic firm load shedding

RC BA TOP DP Each DP or TOP that experiences the Impact Event

Firm load shedding ge 100 MW (manually or via automatic undervoltage or underfrequency load shedding schemes or SPSRAS)

Within 24 hours1 hour after occurrenceevent is initiated

Voltage Deviations on BES Facilities

Each RC TOP GOP that experiences the Impact Event

plusmn 10 sustained for ge 15 continuous minutes Within 24 hours after 15 minute threshold

Frequency Deviations RC BA plusmn Deviations ge than Frequency Trigger Limit (FTL) more than 15 minutes

Within 24 hours after 15 minute threshold

IROL Violation Each RC TOP that experiences the Impact Event

Operate outside the IROL for time greater than IROL Tv

Within 24 hours after Tv threshold






Loss of Firm load for ge 15 Minutes

Each RC BA TO TOP DP that experiences the Impact Event

bull ge 300 MW for entities with previous yearrsquos demand ge 3000 MW

bull ge 200 MW for all other entities

Within 24 hours1 hour after 15 minute threshold

System Separation (Islanding)

Each RC BA TOP DP that experiences the Impact Event

Each separation resulting in an island of generation and load ge 100 MW

Within 1 hour after occurrence is identified

Generation loss Each RC BA GO GOP that experiences the Impact Event

bull ge 2000 MW for entities in the Eastern or Western Interconnection

bull ge 1000 MW for entities in the ERCOT or Quebec Interconnection

bull An entire generating station of ge 5 generators with aggregate capacity of ge 500 MW

Within 24 hours after occurrence

Loss of Off-site power to a nuclear generating plant (grid supply)

Each RC BA TO TOP GO GOP that experiences the Impact Event

Affecting a nuclear generating station per the Nuclear Plant Interface Requirement

Report within 24 hours after occurrence

Transmission loss Each RC TO TOP that experiences the Impact Event

bull An entire DC converter station Multiple BES transmission elements (simultaneous or common-mode event)Three or more BES Transmission Elements


Damage or destruction of BES equipment1equipment1

Each RC BA TO TOP GO GOP DP that experiences the Impact Event

Through operational error equipment failure or external cause or intentional or unintentional human action


1BES equipment that i) Affects an IROL ii) Significantly affects the reliability margin of the system (eg has the potential to result in the need for emergency actions) iii) Damaged or destroyed due to intentional or unintentional human action or iv) Do not report copper theft from BES equipment unless it degrades the ability of equipment to operate correctly eg removal of grounding straps rendering protective relaying inoperative






Damage or destruction of Critical Asset

Applicable Entities under CIP-002 or its successor

Through operational error equipment failure external cause or intentional or unintentional human action


Damage or destruction of a Critical Cyber Asset


Through intentional or unintentional human action


Examples

a BES equipment that is i A critical asset

ii Affects an IROL iii Significantly affects the reliability margin of the system eg has the potential to result in the need for emergency

actions iv Damaged or destroyed due to a non-environmental external cause

Report copper theft from BES equipment only if it degrades the ability of equipment to operate correctly eg removal of grounding straps rendering protective relaying ineffective



EOP-004 ndash Attachment 1 - Potential Reliability Impact ndash Part B

Event Entity with Reporting

Responsibility


Unplanned Control Center evacuation

Each RC BA TOP that experiences the potential Impact Event

Unplanned evacuation from BES control center facility

reportReport within 124 hour after occurrence

Fuel supply emergency Each RC BA GO GOP that experiences the potential Impact Event

Affecting BES reliability1reliability2


Loss of off-site power (grid supply)

RC BA TO TOP GO GOP

Affecting a nuclear generating station

report within 1 hour after occurrence

Loss of all monitoring or voice communication capability


Affecting a BES control center for ge 30 continuous minutes

reportReport within 1 hour24 hours after occurrence

Forced intrusion2intrusion3 Each RC BA TO TOP GO GOP that experiences the

At a BES facility reportReport within 24 hours1 hour after occurrenceverification of intrusion

2 Report if problems with the fuel supply chain result in the projected need for emergency actions to manage reliability 3 Report if you cannot reasonably determine likely motivation (ie intrusion to steal copper or spray graffiti is not reportable unless it effects the reliability of the BES)



potential Impact Event

Risk to BES equipment3equipment4

Each RC BA TO TOP GO GOP DP that experiences the potential Impact Event

From a non-environmental physical threat

reportReport within 24 hours1 hour after occurrenceidentification

Detection of a cyber intrusion to critical cyber assetsreportable Cyber Security Incident


That meets the criteria in CIP-008 (or its successor)

reportReport within 24 hours1 hour after occurrencedetection

1 Report if problems with the fuel supply chain result in the projected need for emergency actions to manage reliability 2 Report if you cannot reasonably determine likely motivation (ie intrusion to steal copper or spray graffiti is not reportable unless

it effects the reliability of the BES) Examples include a train derailment adjacent to BES equipment that either could have damaged the equipment directly or has the potential to damage the equipment (eg flammable or toxic cargo that could pose fire hazard or could cause evacuation of a BES facility control center)

4 Examples include a train derailment adjacent to BES equipment that either could have damaged the equipment directly or has the potential to damage the equipment (eg flammable or toxic cargo that could pose fire hazard or could cause evacuation of a BES facility control center) and report of suspicious device near BES equipment)



EEOOPP--000022000044 -- AAttttaacchhmmeenntt 22 IImmppaacctt EEvveenntt RReeppoorrttiinngg FFoorrmm This form is to be used to report Impact Events to the ERO NERC will accept the DOE OE-417 form in lieu of this form if the entity is required to submit an OE-417 report Reports should be submitted via one of the following e-mail esisacnerccom Facsimile 609-452-9550

EOP-004 ndash Confidential Impact Event ReportReporting for EOP-004-2

Task Comments

1

Entity filing the report (include company name and Compliance Registration ID number)

2 Date and Time of impact eventImpact Event Date (mmddyyyyyy)

TimeZone

3 Name of contact person Email address Telephone Number

4 Did the impact eventactual or potential Impact Event originate in your system

Actual Impact Event Potential Impact Event

Yes No Unknown

5 Under which NERC function are you reporting (RC TOP BA other)

Formatted Table




Task Comments

6 Brief Description of impact eventactual or potential Impact Event (More detail should be provided in the Sequence of Events section below)

7 Generation tripped off-line

MW Total List units tripped

8 Frequency

Just prior to impact eventImpact Event (Hz) Immediately after impact eventImpact Event

(Hz max) Immediately after impact eventImpact Event

(Hz min)

9 List transmission facilities (lines transformers buses etc) tripped and locked-out

(Specify voltage level of each facility listed)

10 Demand tripped (MW))

FIRM INTERRUPTIBLE

Formatted Table




Task Comments

Number of affected customers

Demand lost (MW-Minutes))

11 Restoration Time INITIAL FINAL

Transmission

Generation

Demand

12 Sequence of Events

Sequence of Events of actual or potential Impact Event (if potential Impact Event please describe your assessment of potential impact to BES)

Formatted Table




Task Comments

13 Identify the initial probable cause or known root cause of the impact eventactual or potential Impact Event if known at time of submittal of Part I of this report

14 Identify any protection system misoperation(s))1

15 Additional Information that the helps to further explain the eventactual or potential Impact Event if needed A one-line diagram may be attached if readily available to assist in the evaluation of the event

1 Only applicable if it is part of the impact event the responsible entity is reporting on

Formatted Table




Task Comments

Formatted Table



GGuuiiddeelliinnee aanndd TTeecchhnniiccaall BBaassiiss Disturbance and Sabotage Reporting Standard Drafting Team (Project 2009-01) - Reporting Concepts IInnttrroodduuccttiioonn The SAR for Project 2009-01 Disturbance and Sabotage Reporting was moved forward for standard drafting by the NERC Standards Committee in August of 2009 The Disturbance and Sabotage Reporting Standard Drafting Team (DSR SDT) was formed in late 2009 and is progressing toward developing standards based on the SAR This concepts paper is designed to solicit stakeholder input regarding the proposed reporting concepts that the DSR SDT has developed The standards listed under the SAR are

bull CIP-001 mdash Sabotage Reporting bull EOP-004 mdash Disturbance Reporting

The DSR SDT also proposed to investigate incorporation of the cyber incident reporting aspects of CIP-008 under this project This will be coordinated with the Cyber Security - Order 706 SDT (Project 2008-06) The DSR SDT has reviewed the existing standards the SAR issues from the NERC database and FERC Order 693 Directives to determine a prudent course of action with respect to these standards This concept paper provides stakeholders with a proposed ldquoroad maprdquo that will be used by the DSR SDT in updating or revising CIP-001 and EOP-004 This concept paper provides the background information and thought process of the DSR SDT The proposed changes do not include any real-time operating notifications for the types of events covered by CIP-001 and EOP-004 The real-time reporting requirements are achieved through the RCIS and are covered in other standards (eg EOP-002-Capacity and Energy Emergencies) The proposed standards deal exclusively with after-the-fact reporting The DSR SDT is proposing to consolidate disturbance and event reporting under a single standard These two components and other key concepts are discussed in the following sections



SSuummmmaarryy ooff CCoonncceeppttss aanndd AAssssuummppttiioonnss The Standard Will Require use of a single form to report disturbances and ldquoimpact eventsImpact Eventsrdquo that threaten the reliability of the bulk electric system

bull Provide clear criteria for reporting bull Include consistent reporting timelines bull Identify appropriate applicability including a reporting hierarchy in the case of

disturbance reporting bull Provide clarity around of who will receive the information

The drafting team will explore other opportunities for efficiency such as development of an electronic form and possible inclusion of regional reporting requirements

Discussion of Disturbance Reporting Disturbance reporting requirements currently exist in EOP-004 The current approved definition of Disturbance from the NERC Glossary of Terms is

1 An unplanned event that produces an abnormal system condition

2 Any perturbation to the electric system

3 The unexpected change in ACE that is caused by the sudden failure of generation or interruption of load

Disturbance reporting requirements and criteria are in the existing EOP-004 standard and its attachments The DSR SDT discussed the reliability needs for disturbance reporting and developed the list of impact eventsImpact Events that are to be reported under this standard (attachment 1) Discussion of ldquoimpact eventImpact Eventrdquo Reporting There are situations worthy of reporting because they have the potential to impact reliability The DSR SDT proposes calling such incidents lsquoimpact eventsrsquoImpact Eventsrsquo with the following concept

An impact eventImpact Event is any situation that has the potential to significantly impact the reliability of the Bulk Electric System Such events may originate from malicious intent accidental behavior or natural occurrences

Impact eventEvent reporting facilitates situationalindustry awareness which allows potentially impacted parties to prepare for and possibly mitigate the reliability risk It also provides the raw material in the case of certain potential reliability threats to see emerging patterns Examples of impact eventsImpact Events include

bull Bolts removed from transmission line structures bull Detection of cyber intrusion that meets criteria of CIP-008 or its successor standard bull Forced intrusion attempt at a substation



bull Train derailment near a transmission right-of-way bull Destruction of Bulk Electrical System equipment

What about sabotage One thing became clear in the DSR SDTrsquos discussion concerning sabotage everyone has a different definition The current standard CIP-001 elicited the following response from FERC in FERC Order 693 paragraph 471 which states in part ldquo the Commission directs the ERO to develop the following modifications to the Reliability Standard through the Reliability Standards development process (1) further define sabotage and provide guidance as to the triggering events that would cause an entity to report a sabotage eventrdquo Often the underlying reason for an event is unknown or cannot be confirmed The DSR SDT believes that reporting material risks to the Bulk Electrical System using the impact eventImpact Event categorization it will be easier to get the relevant information for mitigation awareness and tracking while removing the distracting element of motivation The DST SDT discussed the reliability needs for impact eventImpact Event reporting and will consider guidance found in the document ldquoNERC Guideline Threat and Incident Reportingrdquo in the development of requirements which will include clear criteria for reporting Certain types of impact eventsImpact Events should be reported to NERC the Department of Homeland Security (DHS) the Federal Bureau of Investigation (FBI) andor Provincial or local law enforcement Other types of impact eventsImpact Events may have different reporting requirements For example an impact eventImpact Event that is related to copper theft may only need to be reported to the local law enforcement authorities Potential Uses of Reportable Information Event analysis correlation of data and trend identification are a few potential uses for the information reported under this standard As envisioned the standard will only require Functional entities to report the incidents and provide information or data necessary for these analyses Other entities (eg ndash NERC Law Enforcement etc) will be responsible for performing the analyses The NERC Rules of Procedure (section 800) provide an overview of the responsibilities of the ERO in regards to analysis and dissemination of information for reliability Jurisdictional agencies (which may include DHS FBI NERC RE FERC Provincial Regulators and DOE) have other duties and responsibilities Collection of Reportable Information or ldquoOne stop shoppingrdquo The goal of the DSR SDT is to have one reporting form for all functional entities (US Canada Mexico) to submit to NERC Ultimately it may make sense to develop an electronic version to expedite completion sharing and storage Ideally entities would complete a single form which could then be distributed to jurisdictional agencies and functional entities as appropriate Specific reporting forms6

6 The DOE Reporting Form OE-417 is currently a part of the EOP-004 standard If this report is removed from the standard it should be noted that this form is still required by law as noted on the form NOTICE This report is mandatory under Public Law 93-275 Failure to comply may result in criminal fines civil penalties and other

that exist today (ie - OE-417 etc) could be included as part of the



electronic form to accommodate US entities with a requirement to submit the form or may be removed (but still be mandatory for US entities under Public Law 93-275) to streamline the proposed consolidated reliability standard for all North American entities (US Canada Mexico) Jurisdictional agencies may include DHS FBI NERC RE FERC Provincial Regulators and DOE Functional entities may include the RC TOP and BA for situationalindustry awareness Applicability of the standard will be determined based on the specific requirements The DSR SDT recognizes that some regions require reporting of additional information beyond what is in EOP-004 The DSR SDT is planning to update the listing of reportable events from discussions with jurisdictional agencies NERC Regional Entities and stakeholder input There is a possibility that regional differences may still exist The reporting proposed by the DSR SDT is intended to meet the uses and purposes of NERC The DSR SDT recognizes that other requirements for reporting exist (eg DOE-417 reporting) which may duplicate or overlap the information required by NERC To the extent that other reporting is required the DSR SDT envisions that duplicate entry of information is not necessary and the submission of the alternate report will be acceptable to NERC so long as all information required by NERC is submitted For example if the NERC Report duplicates information from the DOE form the DOE report may be included or attached to the NERC report in lieu of entering that information on the NERC report

sanctions as provided by law For the sanctions and the provisions concerning the confidentiality of information submitted on this form see General Information portion of the instructions Title 18 USC 1001 makes it a criminal offense for any person knowingly and willingly to make to any Agency or Department of the United States any false fictitious or fraudulent statements as to any matter within its jurisdiction

Standard CIP-001-1 mdash Sabotage Reporting

Adopted by Board of Trustees November 1 2006 Page 1 of 3 Effective Date January 1 2007

A Introduction 1 Title Sabotage Reporting 2 Number CIP-001-1 3 Purpose Disturbances or unusual occurrences suspected or determined to be

caused by sabotage shall be reported to the appropriate systems governmental agencies and regulatory bodies

4 Applicability 41 Reliability Coordinators 42 Balancing Authorities 43 Transmission Operators 44 Generator Operators 45 Load Serving Entities

5 Effective Date January 1 2007

B Requirements R1 Each Reliability Coordinator Balancing Authority Transmission Operator Generator

Operator and Load Serving Entity shall have procedures for the recognition of and for making their operating personnel aware of sabotage events on its facilities and multi-site sabotage affecting larger portions of the Interconnection

R2 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall have procedures for the communication of information concerning sabotage events to appropriate parties in the Interconnection

R3 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall provide its operating personnel with sabotage response guidelines including personnel to contact for reporting disturbances due to sabotage events

R4 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall establish communications contacts as applicable with local Federal Bureau of Investigation (FBI) or Royal Canadian Mounted Police (RCMP) officials and develop reporting procedures as appropriate to their circumstances

C Measures M1 Each Reliability Coordinator Balancing Authority Transmission Operator Generator

Operator and Load Serving Entity shall have and provide upon request a procedure (either electronic or hard copy) as defined in Requirement 1

M2 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall have and provide upon request the procedures or guidelines that will be used to confirm that it meets Requirements 2 and 3



M3 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall have and provide upon request evidence that could include but is not limited to procedures policies a letter of understanding communication records or other equivalent evidence that will be used to confirm that it has established communications contacts with the applicable local FBI or RCMP officials to communicate sabotage events (Requirement 4)

D Compliance 1 Compliance Monitoring Process

11 Compliance Monitoring Responsibility Regional Reliability Organizations shall be responsible for compliance monitoring

12 Compliance Monitoring and Reset Time Frame One or more of the following methods will be used to verify compliance

- Self-certification (Conducted annually with submission according to schedule)

- Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare)

- Periodic Audit (Conducted once every three years according to schedule)

- Triggered Investigations (Notification of an investigation must be made within 60 days of an event or complaint of noncompliance The entity will have up to 30 days to prepare for the investigation An entity may request an extension of the preparation period and the extension will be considered by the Compliance Monitor on a case-by-case basis)

The Performance-Reset Period shall be 12 months from the last finding of non-compliance

13 Data Retention Each Reliability Coordinator Transmission Operator Generator Operator Distribution Provider and Load Serving Entity shall have current in-force documents available as evidence of compliance as specified in each of the Measures

If an entity is found non-compliant the entity shall keep information related to the non-compliance until found compliant or for two years plus the current year whichever is longer

Evidence used as part of a triggered investigation shall be retained by the entity being investigated for one year from the date that the investigation is closed as determined by the Compliance Monitor

The Compliance Monitor shall keep the last periodic audit report and all requested and submitted subsequent compliance records




None

2 Levels of Non-Compliance 21 Level 1 There shall be a separate Level 1 non-compliance for every one of the

following requirements that is in violation

211 Does not have procedures for the recognition of and for making its operating personnel aware of sabotage events (R1)

212 Does not have procedures or guidelines for the communication of information concerning sabotage events to appropriate parties in the Interconnection (R2)

213 Has not established communications contacts as specified in R4

22 Level 2 Not applicable

23 Level 3 Has not provided its operating personnel with sabotage response procedures or guidelines (R3)

24 Level 4Not applicable

E Regional Differences None indicated

Version History Version Date Action Change Tracking


0 August 8 2005 Removed ldquoProposedrdquo from Effective Date

Errata

1 November 1 2006

Adopted by Board of Trustees Amended

Standard EOP-004-1 mdash Dis tu rbance Reporting


A Introduction 1 Title Disturbance Reporting 2 Number EOP-004-1 3 Purpose Disturbances or unusual occurrences that jeopardize the operation of the

Bulk Electric System or result in system equipment damage or customer interruptions need to be studied and understood to minimize the likelihood of similar events in the future

4 Applicability 41 Reliability Coordinators 42 Balancing Authorities 43 Transmission Operators 44 Generator Operators 45 Load Serving Entities 46 Regional Reliability Organizations


B Requirements R1 Each Regional Reliability Organization shall establish and maintain a Regional

reporting procedure to facilitate preparation of preliminary and final disturbance reports

R2 A Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall promptly analyze Bulk Electric System disturbances on its system or facilities

R3 A Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity experiencing a reportable incident shall provide a preliminary written report to its Regional Reliability Organization and NERC

R31 The affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall submit within 24 hours of the disturbance or unusual occurrence either a copy of the report submitted to DOE or if no DOE report is required a copy of the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Report form Events that are not identified until some time after they occur shall be reported within 24 hours of being recognized

R32 Applicable reporting forms are provided in Attachments 1-EOP-004 and 2-EOP-004

R33 Under certain adverse conditions eg severe weather it may not be possible to assess the damage caused by a disturbance and issue a written Interconnection Reliability Operating Limit and Preliminary Disturbance Report within 24 hours In such cases the affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall promptly notify its Regional Reliability Organization(s) and NERC and verbally provide as much information as is available at that



time The affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall then provide timely periodic verbal updates until adequate information is available to issue a written Preliminary Disturbance Report

R34 If in the judgment of the Regional Reliability Organization after consultation with the Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity in which a disturbance occurred a final report is required the affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall prepare this report within 60 days As a minimum the final report shall have a discussion of the events and its cause the conclusions reached and recommendations to prevent recurrence of this type of event The report shall be subject to Regional Reliability Organization approval

R4 When a Bulk Electric System disturbance occurs the Regional Reliability Organization shall make its representatives on the NERC Operating Committee and Disturbance Analysis Working Group available to the affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity immediately affected by the disturbance for the purpose of providing any needed assistance in the investigation and to assist in the preparation of a final report

R5 The Regional Reliability Organization shall track and review the status of all final report recommendations at least twice each year to ensure they are being acted upon in a timely manner If any recommendation has not been acted on within two years or if Regional Reliability Organization tracking and review indicates at any time that any recommendation is not being acted on with sufficient diligence the Regional Reliability Organization shall notify the NERC Planning Committee and Operating Committee of the status of the recommendation(s) and the steps the Regional Reliability Organization has taken to accelerate implementation

C Measures M1 The Regional Reliability Organization shall have and provide upon request as

evidence its current regional reporting procedure that is used to facilitate preparation of preliminary and final disturbance reports (Requirement 1)

M2 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load-Serving Entity that has a reportable incident shall have and provide upon request evidence that could include but is not limited to the preliminary report computer printouts operator logs or other equivalent evidence that will be used to confirm that it prepared and delivered the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Reports to NERC within 24 hours of its recognition as specified in Requirement 31

M3 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator andor Load Serving Entity that has a reportable incident shall have and provide upon request evidence that could include but is not limited to operator logs voice recordings or transcripts of voice recordings electronic communications or other equivalent evidence that will be used to confirm that it provided information verbally as time permitted when system conditions precluded the preparation of a report in 24 hours (Requirement 33)




11 Compliance Monitoring Responsibility NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations

Regional Reliability Organizations shall be responsible for compliance monitoring of Reliability Coordinators Balancing Authorities Transmission Operators Generator Operators and Load-serving Entities

12 Compliance Monitoring and Reset Time Frame One or more of the following methods will be used to assess compliance






13 Data Retention Each Regional Reliability Organization shall have its current in-force regional reporting procedure as evidence of compliance (Measure 1)

Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator andor Load Serving Entity that is either involved in a Bulk Electric System disturbance or has a reportable incident shall keep data related to the incident for a year from the event or for the duration of any regional investigation whichever is longer (Measures 2 through 4)

If an entity is found non-compliant the entity shall keep information related to the noncompliance until found compliant or for two years plus the current year whichever is longer





14 Additional Compliance Information See Attachments

- EOP-004 Disturbance Reporting Form

- Table 1 EOP-004

2 Levels of Non-Compliance for a Regional Reliability Organization 21 Level 1 Not applicable



24 Level 4 No current procedure to facilitate preparation of preliminary and final disturbance reports as specified in R1

3 Levels of Non-Compliance for a Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load- Serving Entity 31 Level 1 There shall be a level one non-compliance if any of the following

conditions exist

311 Failed to prepare and deliver the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Reports to NERC within 24 hours of its recognition as specified in Requirement 31

312 Failed to provide disturbance information verbally as time permitted when system conditions precluded the preparation of a report in 24 hours as specified in R33

313 Failed to prepare a final report within 60 days as specified in R34




E Regional Differences None identified



0 May 23 2005 Fixed reference to attachments 1-EOP-004-0 and 2-EOP-004-0 Changed chart title 1-FAC-004-0 to 1-EOP-004-0 Fixed title of Table 1 to read 1-EOP-004-0 and fixed font

Errata

0 July 6 2005 Fixed email in Attachment 1-EOP-004-0 from infonerccom to esisacnerccom

Errata



0 July 26 2005 Fixed Header on page 8 to read EOP-004-0

Errata


Errata

1 November 1 2006

Adopted by Board of Trustees Revised



Attachment 1-EOP-004 NERC Disturbance Report Form

Introduction These disturbance reporting requirements apply to all Reliability Coordinators Balancing Authorities Transmission Operators Generator Operators and Load Serving Entities and provide a common basis for all NERC disturbance reporting The entity on whose system a reportable disturbance occurs shall notify NERC and its Regional Reliability Organization of the disturbance using the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Report forms Reports can be sent to NERC via email (esisacnerccom) by facsimile (609-452-9550) using the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Report forms If a disturbance is to be reported to the US Department of Energy also the responding entity may use the DOE reporting form when reporting to NERC Note All Emergency Incident and Disturbance Reports (Schedules 1 and 2) sent to DOE shall be simultaneously sent to NERC preferably electronically at esisacnerccom The NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Reports are to be made for any of the following events 1 The loss of a bulk power transmission component that significantly affects the integrity of

interconnected system operations Generally a disturbance report will be required if the event results in actions such as a Modification of operating procedures b Modification of equipment (eg control systems or special protection systems) to

prevent reoccurrence of the event c Identification of valuable lessons learned d Identification of non-compliance with NERC standards or policies e Identification of a disturbance that is beyond recognized criteria ie three-phase fault

with breaker failure etc f Frequency or voltage going below the under-frequency or under-voltage load shed

points 2 The occurrence of an interconnected system separation or system islanding or both 3 Loss of generation by a Generator Operator Balancing Authority or Load-Serving Entity

2000 MW or more in the Eastern Interconnection or Western Interconnection and 1000 MW or more in the ERCOT Interconnection

4 Equipment failuressystem operational actions which result in the loss of firm system demands for more than 15 minutes as described below a Entities with a previous year recorded peak demand of more than 3000 MW are

required to report all such losses of firm demands totaling more than 300 MW b All other entities are required to report all such losses of firm demands totaling more

than 200 MW or 50 of the total customers being supplied immediately prior to the incident whichever is less

5 Firm load shedding of 100 MW or more to maintain the continuity of the bulk electric system



6 Any action taken by a Generator Operator Transmission Operator Balancing Authority or Load-Serving Entity that results in a Sustained voltage excursions equal to or greater than plusmn10 or b Major damage to power system components or c Failure degradation or misoperation of system protection special protection schemes

remedial action schemes or other operating systems that do not require operator intervention which did result in or could have resulted in a system disturbance as defined by steps 1 through 5 above

7 An Interconnection Reliability Operating Limit (IROL) violation as required in reliability standard TOP-007

8 Any event that the Operating Committee requests to be submitted to Disturbance Analysis Working Group (DAWG) for review because of the nature of the disturbance and the insight and lessons the electricity supply and delivery industry could learn



NERC Interconnection Reliability Operating Limit and Preliminary Disturbance

Report

Check here if this is an Interconnection Reliability Operating Limit (IROL) violation report

1 Organization filing report

2 Name of person filing report

3 Telephone number

4 Date and time of disturbance Date(mmddyy)

TimeZone

5 Did the disturbance originate in your system

Yes No

6 Describe disturbance including cause equipment damage critical services interrupted system separation key scheduled and actual flows prior to disturbance and in the case of a disturbance involving a special protection or remedial action scheme what action is being taken to prevent recurrence

7 Generation tripped MW Total

List generation tripped

8 Frequency Just prior to disturbance (Hz)

Immediately after disturbance (Hz max)

Immediately after disturbance (Hz min)

9 List transmission lines tripped (specify voltage level of each line)

10 Demand tripped (MW)

Number of affected Customers




Demand lost (MW-Minutes)

11 Restoration time INITIAL FINAL

Transmission

Generation

Demand



Attachment 2-EOP-004 US Department of Energy Disturbance Reporting Requirements

Introduction The US Department of Energy (DOE) under its relevant authorities has established mandatory reporting requirements for electric emergency incidents and disturbances in the United States DOE collects this information from the electric power industry on Form EIA-417 to meet its overall national security and Federal Energy Management Agencyrsquos Federal Response Plan (FRP) responsibilities DOE will use the data from this form to obtain current information regarding emergency situations on US electric energy supply systems DOErsquos Energy Information Administration (EIA) will use the data for reporting on electric power emergency incidents and disturbances in monthly EIA reports In addition the data may be used to develop legislative recommendations reports to the Congress and as a basis for DOE investigations following severe prolonged or repeated electric power reliability problems Every Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity must use this form to submit mandatory reports of electric power system incidents or disturbances to the DOE Operations Center which operates on a 24-hour basis seven days a week All other entities operating electric systems have filing responsibilities to provide information to the Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity when necessary for their reporting obligations and to file form EIA-417 in cases where these entities will not be involved EIA requests that it be notified of those that plan to file jointly and of those electric entities that want to file separately Special reporting provisions exist for those electric utilities located within the United States but for whom Reliability Coordinator oversight responsibilities are handled by electrical systems located across an international border A foreign utility handling US Balancing Authority responsibilities may wish to file this information voluntarily to the DOE Any US-based utility in this international situation needs to inform DOE that these filings will come from a foreign-based electric system or file the required reports themselves Form EIA-417 must be submitted to the DOE Operations Center if any one of the following applies (see Table 1-EOP-004-0 mdash Summary of NERC and DOE Reporting Requirements for Major Electric System Emergencies) 1 Uncontrolled loss of 300 MW or more of firm system load for more than 15 minutes from a

single incident 2 Load shedding of 100 MW or more implemented under emergency operational policy 3 System-wide voltage reductions of 3 percent or more 4 Public appeal to reduce the use of electricity for purposes of maintaining the continuity of the

electric power system 5 Actual or suspected physical attacks that could impact electric power system adequacy or

reliability or vandalism which target components of any security system Actual or suspected cyber or communications attacks that could impact electric power system adequacy or vulnerability



6 Actual or suspected cyber or communications attacks that could impact electric power system adequacy or vulnerability

7 Fuel supply emergencies that could impact electric power system adequacy or reliability 8 Loss of electric service to more than 50000 customers for one hour or more 9 Complete operational failure or shut-down of the transmission andor distribution electrical

system The initial DOE Emergency Incident and Disturbance Report (form EIA-417 ndash Schedule 1) shall be submitted to the DOE Operations Center within 60 minutes of the time of the system disruption Complete information may not be available at the time of the disruption However provide as much information as is known or suspected at the time of the initial filing If the incident is having a critical impact on operations a telephone notification to the DOE Operations Center (202-586-8100) is acceptable pending submission of the completed form EIA-417 Electronic submission via an on-line web-based form is the preferred method of notification However electronic submission by facsimile or email is acceptable An updated form EIA-417 (Schedule 1 and 2) is due within 48 hours of the event to provide complete disruption information Electronic submission via facsimile or email is the preferred method of notification Detailed DOE Incident and Disturbance reporting requirements can be found at httpwwweiadoegovcneafelectricitypageform_417html



Table 1-EOP-004-0 Summary of NERC and DOE Reporting Requirements for Major Electric System

Emergencies Incident No Incident Threshold Report

Required Time

1 Uncontrolled loss of Firm System Load

ge 300 MW ndash 15 minutes or more

EIA ndash Sch-1 EIA ndash Sch-2

1 hour 48 hour

2 Load Shedding ge 100 MW under emergency operational policy


1 hour 48 hour

3 Voltage Reductions 3 or more ndash applied system-wide


1 hour 48 hour

4 Public Appeals Emergency conditions to reduce demand


1 hour 48 hour

5 Physical sabotage terrorism or vandalism

On physical security systems ndash suspected or real


1 hour 48 hour

6 Cyber sabotage terrorism or vandalism

If the attempt is believed to have or did happen


1 hour 48 hour

7 Fuel supply emergencies

Fuel inventory or hydro storage levels le 50 of normal


1 hour 48 hour

8 Loss of electric service ge 50000 for 1 hour or more


1 hour 48 hour

9

Complete operation failure of electrical system

If isolated or interconnected electrical systems suffer total electrical system collapse


1 hour 48 hour

All DOE EIA-417 Schedule 1 reports are to be filed within 60-minutes after the start of an incident or disturbance All DOE EIA-417 Schedule 2 reports are to be filed within 48-hours after the start of an incident or disturbance



All entities required to file a DOE EIA-417 report (Schedule 1 amp 2) shall send a copy of these reports to NERC simultaneously but no later than 24 hours after the start of the incident or disturbance Incident No Incident Threshold Report

Required Time

1 Loss of major system component

Significantly affects integrity of interconnected system operations

NERC Prelim Final report

24 hour 60 day

2

Interconnected system separation or system islanding

Total system shutdown Partial shutdown separation or islanding


24 hour 60 day

3 Loss of generation ge 2000 ndash Eastern Interconnection ge 2000 ndash Western Interconnection ge 1000 ndash ERCOT Interconnection


24 hour 60 day

4 Loss of firm load ge15-minutes

Entities with peak demand ge3000 loss ge300 MW All others ge200MW or 50 of total demand


24 hour 60 day

5 Firm load shedding

ge100 MW to maintain continuity of bulk system


24 hour 60 day

6

System operation or operation actions resulting in

bull Voltage excursions ge10 bull Major damage to system

components bull Failure degradation or

misoperation of SPS


24 hour 60 day

7 IROL violation Reliability standard TOP-007


72 hour 60 day

8 As requested by ORS Chairman

Due to nature of disturbance amp usefulness to industry (lessons learned)


24 hour 60 day

All NERC Operating Security Limit and Preliminary Disturbance reports will be filed within 24 hours after the start of the incident If an entity must file a DOE EIA-417 report on an incident which requires a NERC Preliminary report the Entity may use the DOE EIA-417 form for both DOE and NERC reports Any entity reporting a DOE or NERC incident or disturbance has the responsibility to also notify its Regional Reliability Organization



Project 2009-01 Disturbance and Sabotage Reporting Implementation Plan Implementation Plan for EOP-004-2 - Impact Event Assessment Analysis and Reporting Prerequisite Approvals None Revisions to Approved Standards and Definitions Retire all requirements of EOP-004-1 and CIP-001-1 Compliance with the Standard The following entities are responsible for being compliant with all requirements of EOP-004-2

bull Reliability Coordinator bull Balancing Authority bull Load-serving Entity bull Interchange Authority bull Transmission Service Provider bull Transmission Owner bull Transmission Operator bull Generator Owner bull Generator Operator bull Distribution Provider

Effective Date The standard shall become effective on the first calendar day of the third calendar quarter after the date of the order providing applicable regulatory approval In those jurisdictions where no regulatory approval is required the standard shall become effective on the first calendar day of the third calendar quarter after Board of Trustees adoption


Project 2009-01 Disturbance and Sabotage Reporting Formal Comment Period Open March 9 ndash April 8 2011 Now available at httpwwwnerccomfilezstandardsProject2009-01_Disturbance_Sabotage_Reportinghtml Formal 30-day Comment Period Open through 8 pm on April 8 2011 The Disturbance and Sabotage Reporting SDT has posted a revised draft of EOP-004-2 mdash Impact Event Reporting along with the associated implementation plan and a redline of EOP-004-2 showing changes made since an informal comment period for this project concluded in October 2010 These documents are posted for a 30-day formal comment period The drafting team proposes to retire CIP-001-1 and incorporate its requirements into EOP-004-2 As a result the changes to EOP-004 are so extensive that a redline showing changes against the last approved version would be impractical For reference the last approved versions of EOP-004 and CIP-001 have been posted Instructions Please use this electronic form to submit comments If you experience any difficulties in using the electronic form please contact Monica Benson at monicabensonnercnet An off-line unofficial copy of the comment form is posted on the project page httpwwwnerccomfilezstandardsProject2009-01_Disturbance_Sabotage_Reportinghtml Next Steps The drafting team will consider all comments and determine whether to make additional changes to the standard The team will post its response to comments and if changes are made to the standard and supporting documents submit the revised documents for quality review prior to ballot Project Background Stakeholders have indicated that identifying potential acts of ldquosabotagerdquo is difficult to do in real time and additional clarity is needed to identify thresholds for reporting potential acts of sabotage in CIP-001-1 Stakeholders have also reported that EOP-004-1 has some requirements that reference out-of-date Department of Energy forms making the requirements ambiguous EOP-004-1 also has some lsquofill-in-the-blankrsquo components to eliminate The project will include addressing previously identified stakeholder concerns and FERC directives will bring the standards into conformance with the latest approved version of the ERO Rules of Procedure and may include other improvements to the standards deemed appropriate by the drafting team with the consensus of stakeholders consistent with establishing high quality enforceable and technically sufficient bulk power system reliability standards

Standards Process The Standard Processes Manual contains all the procedures governing the standards development process The success of the NERC standards development process depends on stakeholder participation We extend our thanks to all those who participate




From Guy V ZitoTo rsballotCc Lee R PedowiczSubject FW Comment Form--Project 2010-11 - TPL Table 1 OrderDate Wednesday January 05 2011 94852 AMAttachments LP--Project_2010-11_Unofficial_Comment_Form-1-5-11doc

NPCC Members of the NERC Registered Ballot Body Attached is a form containing comments submitted with NPCCs Affirmative Vote toaccept the standard Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

Unofficial Comment Form for TPL Table 1 Order (Project 2010-11)

Unofficial Comment Form for TPL Table 1 Order (Project 2010-11)

Please DO NOT use this form to submit comments on the 3rd posting for Project 2010-11 TPL Table 1 Order Please use the electronic comment form posted on the following project page

httpwwwnerccomfilezstandardsProject2010-11_TPL_Table-1_Orderhtml

The electronic comment form must be completed by January 3 2011 This is a 45-day formal comment period

If you have questions please contact Ed Dobrowolski at
eddobrowolskinercnet or by telephone at 609-947-3673
Background Information

The Standard Drafting Team (SDT) posted Table I footnote lsquobrsquo for an informal comment period from September 8 2010 through October 8 2010 Industry response was divided in relation to support for the proposed footnote lsquobrsquo Although there were a number of supporters for the proposed footnote they were outnumbered by the commenters who did not support the footnote text for various reasons and offered their views and concerns

The SDT carefully considered the feedback provided including minority opinions such as not allowing Demand interruption at all and has made clarifying revisions to the footnote lsquobrsquo text

The revisions made to footnote lsquobrsquo following the informal comment period are shown below

b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Demand following Contingency events However it is recognized that Demand will be interrupted if it is directly served by the elements removed from service as a result of the Contingency Furthermore in limited circumstances Demand may need to be interrupted to address BES performance requirements When interruption of Demand is utilized within the planning process to address BES performance requirements such interruption is limited to

middot

middot Interruptible Demand or Demand-Side Management

middot Circumstances where the use of Demand interruption are documented including alternatives evaluated and where the Demand interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments

Please Enter All Comments in Simple Text Format

Insert a ldquocheckrdquo mark in the appropriate boxes by double-clicking the gray areas

1 The SDT is proposing a revision to footnote lsquobrsquo in the TPL tables to comply with a FERC directive which required the ERO to clarify TPL-002-0 Table 1 - footnote lsquobrsquo regarding the planned or controlled interruption of electric supply where a single contingency occurs on a transmission system Do you agree with the proposed changes and if not please provide specific reasons for your disagreement

FORMCHECKBOX Yes

FORMCHECKBOX No

Comments There is concern with the use of the term Demand It is unclear throughout the footnote whether or not the term Demand includes Interruptible Demand or Demand-Side Management It is suggested that interruption of Demand be clarified to not include Interruptible Demand or Demand-Side Management to more clearly show the permitted use of Load shedding It is unclear whether the second bullet includes Demand which is interrupted by the elements removed from service Clarification should be made such that Demand which is interrupted by the elements removed from service should not be included in this bullet

Language that mitigation of Load andor Demand interruption should be pursued within the planning process should be reinstated as reinforcement of a Transmission Providersrsquo planning obligations to their load customers and system operations Footnote lsquobrsquo should be made to read as follows

b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of Load andor Demand following Contingency events Interruption of Load andor Demand is discouraged and all measures to mitigate such interruption should be pursued within the planning process However it is recognized that Load andor Demand will be interrupted if it is directly served by the elements automatically removed from service by the Protection System as a result of a Contingency Furthermore in extraordinary circumstances within the planning process Load andor Demand may need to be interrupted to address BES performance requirements When interruption of Load andor Demand is utilized within the planning process to address BES performance requirements such interruption is limited to

middot Circumstances where the use of Load andor Demand interruption are documented including alternatives evaluated and where the Load andor Demand interruption is made available for review in an open and transparent stakeholder process

If Load andor Demand interruption is necessary planning should indicate the amount needed and not specify how it would be obtained What Load andor Demand is interrupted is an operational decision

Additional comments not included in the material listed for footnote lsquobrsquo on the Comment Form In the paragraph below the bullets in footnote lsquobrsquo confusion is introduced through the use of the term ldquofirm Demandrdquo It is unclear how this is different than the defined term ldquoFirm Demandrdquo and what the implications of the term ldquofirm Demandrdquo are This footnote should not discourage such adjustments which actually increase the reliability of service to end users The last sentence of footnote lsquobrsquo is unnecessary and should be deleted It is never acceptable to cause reliability concerns in another area while addressing your own

116-390 Village BoulevardPrinceton New Jersey 08540-5721

6094528060 | wwwnerccom

3

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Recirculation Ballot Window Open January 26-February 5 2011 - Project 2010-11 TPL Table 1 OrderDate Wednesday January 26 2011 102627 AM

Standards AnnouncementRecirculation Ballot Window Open January 26-February 5 2011Project 2010-11 TPL Table 1 Order Now available at httpsstandardsnercnetCurrentBallotsaspx A recirculation ballot window for standards TPL-001-1 TPL-002-1b TPL-003-1a and TPL-004-1 is open until 8 pm Eastern onSaturday February 5 2011 InstructionsMembers of the ballot pool associated with this project may log in and submit their votes from the following pagehttpsstandardsnercnetCurrentBallotsaspx Ballot ProcessThe Standards Committee encourages all members of the ballot pool to review the consideration of comments submitted during the lastballot window In the recirculation ballot votes are counted by exception only mdash if a ballot pool member does not submit a revision to thatmemberrsquos original vote the vote remains the same as in the first ballot Members of the ballot pool may

Reconsider and change their votes from the first ballot

Vote in the second ballot even if they did not vote on the first ballot

Take no action if they do not want to change their original vote

Additional InformationThe Standard Processes Manual allows drafting teams to make changes following an initial or successive ballot with a goal of improving thequality of a standard provided those changes do not alter the applicability or scope of the proposed standard Following the initial ballot theProject 2010-11 made minor changes to the structure of footnote lsquobrsquo in all of the standards and corrected capitalization of NERC Glossaryterms The standards (clean versions and redlines against the last posted and last approved versions) have been posted on the project page Next StepsVoting results will be posted and announced after the ballot window closes If approved the standards and associated implementation planwill be submitted to the Board of Trustees BackgroundFERC Order RM06-16-009 requires the ERO to clarify TPL-002-0 Table 1 - footnote lsquobrsquo regarding the planned or controlled interruptionof electric supply where a single contingency occurs on a transmission system and originally directed NERC to file the revised standards byJune 30 2010 To meet this directive a proposed revision was posted for ldquoUrgent Actionrdquo and balloted from May 17-27 2010 Theproposed revision achieved a quorum (84) and almost enough affirmative votes (64) to achieve weighted segment approval howevermany balloters provided comments indicating the need for additional modifications Following the initial ballot FERC extended the duedate to March 31 2011 thus the project is no longer considered ldquoUrgent Actionrdquo Because Table 1 appears in TPL-001 TPL-002 TPL-003 and TPL-004 the change is reflected in all four standards

TPL-001-1 - System Performance Under Normal (No Contingency) Conditions (Category A)

TPL-002-1b - System Performance Following Loss of a Single Bulk Electric System Element (Category B)

TPL-003-1a - System Performance Following Loss of Two or More Bulk Electric System Elements (Category C)

TPL-004-1 - System Performance Following Extreme Events Resulting in the Loss of Two or More Bulk Electric System Elements(Category D)

More details may be found on the project pagehttpwwwnerccomfilezstandardsProject2010-11_TPL_Table-1_Orderhtml Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate

For more information or assistance please contact Monica Benson at monicabensonnercnet

North American Electric Reliability Corporation



---You are currently subscribed to nerc-info as lpedowicznpccorgTo unsubscribe send a blank email to leave-1245756-3256541ca6f85fb1574a8515cc07df72d3bfe0listservnerccom

From Monica BensonTo monicabensonnercnetSubject Standards Announcement Recirculation Ballot Results | Project 2010-11 TPL Table 1 Footnote BDate Thursday February 10 2011 111522 AM

Standards AnnouncementProject 2010-11 TPL Table 1 Footnote BRecirculation Ballot Results Now available at httpsstandardsnercnetBallotsaspx A recirculation ballot of Table 1 footnote lsquobrsquo in TPL-001-1 through TPL-004-1 ended on February 5 2011 The standards were approved Voting statistics are listed below and the Ballot Results Web page provides a link to the detailed results Quorum 9361 Approval 8654 BackgroundFERC Order RM06-16-009 requires the ERO to clarify TPL-002-0 Table 1 - footnote lsquobrsquo regarding the planned or controlled interruptionof electric supply where a single contingency occurs on a transmission system and originally directed NERC to file the revised standardsby June 30 2010 To meet this directive a proposed revision was posted for ldquoUrgent Actionrdquo and balloted from May 17-27 2010 Theproposed revision achieved a quorum (84) and almost enough affirmative votes (64) to achieve weighted segment approval howevermany balloters provided comments indicating the need for additional modifications Following the initial ballot FERC extended the duedate to March 31 2011 thus the project is no longer considered ldquoUrgent Actionrdquo Because Table 1 appears in TPL-001 TPL-002 TPL-003 and TPL-004 the change is reflected in all four standards





More details may be found on the project pagehttpwwwnerccomfilezstandardsProject2010-11_TPL_Table-1_Orderhtml Next StepsThe standards will go to the Board of Trustees for adoption Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Guy V ZitoTo rscSubject FW Standards Announcement Project 2007-07 Transmission Vegetation Management - Successive Ballot ResultsDate Thursday March 03 2011 120535 PM

RSC The below successive ballot passed but will go to a recirc ballot after comments are answered Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica Benson [MonicaBensonnercnet]Sent Thursday March 03 2011 1147 AMTo monicabensonnercnetSubject Standards Announcement Project 2007-07 Transmission Vegetation Management - Successive Ballot Results

Standards AnnouncementProject 2007-07 Transmission Vegetation ManagementSuccessive Ballot Results Now available at httpsstandardsnercnetBallotsaspx Ballot Results for Revisions to FAC-003A successive ballot on revisions to FAC-003 - Transmission Vegetation Management and a concurrent non-binding poll of associatedVRFs and VSLs concluded on February 28 2011 Voting statistics are listed below and the Ballot Results Web page provides a link to the detailed resultsQuorum 7928 Approval 7934 Violation Risk Factor (VRF) and Violation Severity Level (VSL) Non-binding Poll ResultsFor the non-binding poll of VRFs and VSLs 77 of those who registered to participate provided an opinion 79 of those who providedan opinion indicated support for the VRFs and VSLs that were proposed Next StepsThe drafting team will post its consideration of all comments (those submitted with a comment form and those submitted with a ballot)

BackgroundFAC-003-1 is being revised to address several fill-in-the-blank requirements directives from Order 693 and issues raised by stakeholders An initial ballot closed in July 2010 and achieved a quorum of 8618 and an approval of 6593 The drafting team has posted itsconsideration of comments received both those submitted with a ballot as well as those submitted with a comment form In addition aQuality Review was conducted in November 2010 and the drafting team revised the draft standard and technical reference in response tocomments and input from the Quality Review Further details are available on the project page httpwwwnerccomfilezstandardsVegetation-Management_Project_2007-7html

Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate



116-390 Village Blvd

Princeton NJ 085406094528060 | wwwnerccom

---You are currently subscribed to nercroster as gzitonpccorgTo unsubscribe send a blank email to leave-1249959-3920898eac8c94409e17058b6e89bfa4b2626listservnerccom

From Guy V ZitoTo rsballotCc rscSubject Project 2007-07 ― Vegetation Management ― FAC-003Date Tuesday February 22 2011 81239 AMImportance High

NPCC Members of the NERC Registered Ballot Body The Regional Standards Committee has reviewed and sought opinions from subject matter expertsin the northeast on the subject draft standard currently posted for ballot though Feb 28 2011 The RSC recommends an affirmative or YES vote however the group will be submitting somecomments requesting that the Drafting Team clarify the term ldquoencroachmentrdquo

This is a ldquosuccessiverdquo ballot Even if no substantive revision is needed in order to obtain a passingvote tally there will be a recirculation ballot If however the comments submitted indicate a needto draft a substantially revised standard there will be another successive ballot conducted TheRSC will keep you informed Thank-you Guy V ZitoAsst Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Successive Ballot and Non-binding Poll Open | Project 2007-07 Vegetation ManagementDate Friday February 18 2011 104229 AM

Standards AnnouncementSuccessive Ballot and Non-binding Poll OpenProject 2007-07 ndash Vegetation ManagementFebruary 18 ndash February 28 2011 Now available at httpsstandardsnercnetCurrentBallotsaspx Project 2007-07 ndash Vegetation ManagementA successive ballot window for FAC-003-2 ndash Transmission Vegetation Management and its associated implementation plan is open through8 pm on February 28 2011 In addition members of this ballot pool will be able to vote in a concurrent non-binding poll on the standardrsquos Violation Risk Factors(VRFs) and Violation Severity Levels (VSLs) Members who joined the ballot pool to vote on the standard were automatically entered in aseparate pool to participate in the non-binding poll for the VRFs and VSLs The non-binding poll will appear in the list of current ballotsand is labeled accordingly InstructionsMembers of the ballot pool associated with this project may log in and submit their votes from the following pagehttpsstandardsnercnetCurrentBallotsaspx BackgroundFAC-003-1 is being revised to address several fill-in-the-blank requirements directives from Order 693 and issues raised by stakeholders An initial ballot closed in July 2010 and achieved a quorum of 8618 and an approval of 6593 The drafting team has posted itsconsideration of comments received both those submitted with a ballot as well as those submitted with a comment form In addition aQuality Review was conducted in November 2010 and the drafting team revised the draft standard and technical reference in response tocomments and input from the Quality Review Documents for this project including clean and redline to the last posted versions of the standard implementation plan and technicalreference and an unofficial copy of the questions listed in the comment forms are posted on the project web page athttpwwwnerccomfilezstandardsVegetation-Management_Project_2007-7html Next StepsVoting results will be posted and announced after the ballot window closes and the drafting team will consider all comments includingthose submitted with a comment form and those submitted with a ballot Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate





---You have received this email because you are a registered representative in the Registered Ballot Body

From Guy V ZitoTo rscSubject FW Standards Announcement Project 2006-06 ndash Reliability Coordination | Initial Ballot ResultsDate Wednesday March 09 2011 44527 PM

FYI Ballot failed The DT will revise the standard based on comments submitted with the ballots and conduct a successive ballot I willfollow this closely and keep you all informed You will recall the issue of contention in this project was pertaining to use and meaning ofthe term Directive Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica Benson [MonicaBensonnercnet]Sent Wednesday March 09 2011 403 PMTo monicabensonnercnetSubject Standards Announcement Project 2006-06 ndash Reliability Coordination | Initial Ballot Results

Standards AnnouncementProject 2006-06 ndash Reliability CoordinationInitial Ballot Results

Now available at httpsstandardsnercnetBallotsaspx An initial ballot of the following standards and their associated implementation plans ended on March 7 2011

middot COM-001-2 ndash Communications

middot COM-002-3 ndash Communication and Coordination

middot IRO-001-2 ndash Reliability Coordination ndash Responsibilities and Authorities

middot IRO-002-2 ndash Reliability Coordination ndash Analysis Tools

middot IRO-005-4 ndash Reliability Coordination ndash Current Day Operations

middot IRO-014-2 ndash Coordination Among Reliability Coordinators

middot IRO-015-1 ndash Notifications and Information Exchange Between Reliability Coordinators

middot IRO-016-1 ndash Coordination of Real-time Activities Between Reliability Coordinators

Voting statistics are listed below and the Ballot Results Web page provides a link to the detailed results Quorum 8710Approval 4954 BackgroundThe Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related requirements applicable to theReliability Coordinator are clear measurable unique and enforceable 2) ensuring that this set of requirements is sufficient to maintainreliability of the Bulk Electric System and 3) revising the group of standards based on FERC Order 693 During the course of this project the Reliability Coordination Standards Drafting Team incorporated changes due to the work of the IROLStandards Drafting Team Two standards from the original Standards Authorization Request (PER-004 and PRC-001) were moved to otherprojects due to scope overlap In addition the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693associated with standards IRO-003-2 For more information review the project Web page

httpwwwnerccomfilezstandardsReliability_Coordination_Project_2006-6html Next StepsThe drafting team will consider all comments (those submitted with a comment form and those submitted with a ballot Once the team hasprepared its response to comments and made any changes to the standards and supporting documents they will submit the reviseddocuments for quality review prior to a successive ballot Since a non-binding poll of VRFs and VSLs was not conducted concurrent withthe initial ballot that concluded on March 7 2011 a non-binding poll will be conducted in conjunction with the successive ballot Ballot CriteriaApproval requires both (1) a quorum which is established by at least 75 of the members of the ballot pool submitting either anaffirmative vote a negative vote or an abstention and (2) a two-thirds majority of the weighted segment votes cast must be affirmative thenumber of votes cast is the sum of affirmative and negative votes excluding abstentions and non-responses Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate




6094528060 | wwwnerccom ---You are currently subscribed to nercroster as gzitonpccorgTo unsubscribe send a blank email to leave-1250569-3920898eac8c94409e17058b6e89bfa4b2626listservnerccom

From Guy V ZitoTo rsballotCc rscSubject NERC Ballot for Project 2006-06 Reliability Coordination COM-001 COM-002 IRO-001 and IRO-014Date Thursday March 03 2011 115530 AM

NPCC Members of the NERC Registered Ballot Body As FYI subsequent to the RSC recommendation sent out earlier this week toaccept and vote Affirmative on the subject project some RSC membershave indicated their intent to cast an abstention on the ballot untilsuch time as there is clarification to COM-002 (ie pre-establisheddocumentation of when 3-part communications will be employed) isincluded in the Standard These entities have expressed the opinionthat this position is a direct result of the concurrent balloting andcommenting resulting in uncertainty as to what is actually beingvotedGuy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Guy V ZitoTo rsballotCc rscSubject NERC Initial Ballot NPCC Recommendation-Project 2006-06 ― Reliability Coordination ― COM-001 COM-002

IRO-001 and IRO-014Date Wednesday March 02 2011 81933 AMImportance High

NPCC Members of the NERC Registered Ballot Body The subject Project and associated standards are currently posted at NERC and anInitial ballot is being conducted through March 7 2011 Comments are also being accepteduntil this time The RSC has reviewed the subject project and standards and has identified no showstoppersand therefore recommends an Affirmative vote to accept the standards within this project One of the more substantive non-grammatical or format related requirment that the RSC willsubmit is in relation to the issue of classifying data as part of the InterpersonalCommunications This would then require three part communication to be applied to thisdata NPCC pointed this out to the DT however the DT responded that Interpersonalcommunication implicitly was meant to refer to interpersonal or between two persons NPCC believes that perhaps a future revision will better clarify that data is not and will beincluded in the three part communication requirment

Please contact me if you have further questions Thank-you Guy V Zito Chair Regional Standards CommitteAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Ballot Window Open February 25 - March 7 2011 | Project 2006-06Date Thursday February 24 2011 42208 PM

Standards AnnouncementBallot Window Open February 25 ndash March 7 2011Project 2006-06 ndash Reliability Coordination Available Friday February 25th at httpsstandardsnercnetCurrentBallotsaspx Initial Ballot Window Open February 25th through 8 pm on March 7 2011An initial ballot for the following standards and associated implementation plans will be open from 800 am on Friday February 25through 800 pm on Monday March 7 2011 bull COM-001-2 ndash Communicationsbull COM-002-3 ndash Communication and Coordinationbull IRO-001-2 ndash Reliability Coordination ndash Responsibilities and Authoritiesbull IRO-002-2 ndash Reliability Coordination ndash Analysis Toolsbull IRO-005-4 ndash Reliability Coordination ndash Current Day Operationsbull IRO-014-2 ndash Procedures Processes or Plans to Support Coordination Between Reliability Coordinatorsbull IRO-015-1 ndash Notifications and Information Exchange Between Reliability Coordinatorsbull IRO-016-1 ndash Coordination of Real-time Activities Between Reliability Coordinators During the initial ballot window members of the ballot pool associated with this project may log in and submit their votes from thefollowing page httpsstandardsnercnetCurrentBallotsaspx BackgroundThe Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related requirements applicable to theReliability Coordinator are clear measurable unique and enforceable 2) ensuring that this set of requirements is sufficient to maintainreliability of the Bulk Electric System and 3) revising the group of standards based on FERC Order 693 During the course of this project the Reliability Coordination Standards Drafting Team incorporated changes due to the work of the IROLStandards Drafting Team Two standards from the original Standards Authorization Request (PER-004 and PRC-001) were moved to otherprojects due to scope overlap In addition the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693associated with standards IRO-003-2 For more information review the project Web pagehttpwwwnerccomfilezstandardsReliability_Coordination_Project_2006-6html Next StepsThe comments submitted during the formal comment period and the ballot results will be posted Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate





---

You have received this email because you are a registered representative in the Registered Ballot Body

From Guy V ZitoTo rscSubject FW Standards Announcement Non-binding Polls for VSLs Now Open - October 27-November 6 2010 | Project 2007-23Date Thursday October 28 2010 114726 AM

RSC I would like to send a recommendation to accept the VSLs as written to the voting membership of NPCC As discussed at the RSCmeeting last week there were no identified issues with them as written but on a going forward basis I think we need a subgroup to helpwith their review If you are opposed to reccommending an Affirmative vote for these ballots please so indicate Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica Benson [MonicaBensonnercnet]Sent Wednesday October 27 2010 205 PMTo monicabensonnercnetSubject Standards Announcement Non-binding Polls for VSLs Now Open - October 27-November 6 2010 | Project 2007-23

Standards AnnouncementNon-binding Polls for VSLs Now OpenOctober 27-November 6 2010

Available at httpsstandardsnercnetCurrentBallotsaspx Project 2007-23 Violation Severity LevelsThe windows for submitting opinions on each of the six sets of Violation Severity Levels (VSLs) shown below are open through 8 pmEastern on November 6 2010 VSLs - Balancing Resources and Demand (BAL) and Interchange (INT)VSLs - Interconnected Reliability Operations (IRO)VSLs ndash Nuclear (NUC) Transmission Operations (TOP) and Voltage and Reactive (VAR)VSLs ndash Communications (COM) Emergency Operations (EOP) Personnel (PER)VSLs - Facilities (FAC) and Modeling (MOD)VSLs - Protection and Control (PRC) Transmission Planning (TPL)

InstructionsMembers of the ballot pools associated with these sets of VSLs may log in and submit their opinions from the following pagehttpsstandardsnercnetCurrentBallotsaspx Next StepsThe results of the non-binding polls will be posted Project BackgroundIn its June 19 2008 VSL Order FERC directed NERC to review all VSLs (with the exception of those for which the Commission directedspecific modification) for compliance with FERCrsquos VSL Guidelines 2b 3 and 4 and submit a compliance filing either validating thecurrent Violation Severity Level assignments or proposing revision

middot Guideline 2b mdash VSLs should not use ambiguous terms such as minor or significant to describe noncompliant performance

middot Guideline 3 mdash VSLs should be consistent with the corresponding requirement (VSLs should not expand on what is in therequirement)

middot Guideline 4 mdash VSLs should be based on a single violation not on a cumulative number of violations (unless stated otherwise in therequirement)

The VSLs have been reviewed balloted and reviewed again for consistency with the FERC Guidelines The review subsequent to the lastballot identified some discrepancies and inconsistencies in the VSL assignments last balloted The VSLs that met all the Guidelines werefiled with FERC earlier this year The remaining VSLs must be filed with FERC by December 1 2010Project page httpwwwnerccomfilezstandardsVSLs_Project_2007-23html Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Project 2007-23 | Violation Severity LevelsDate Thursday January 20 2011 41127 PM

Standards AnnouncementExisting Ballot Pool Re-opened January 20-February 9 2011Comment Period Open January 20-February 18 2011Project 2007-23 ndash Violation Severity Levels Now available at httpsstandardsnercnetBallotPoolaspx The Violation Severity Level Drafting Team has made revisions to 14 sets of VSL assignments and the revisions have been posted forindustry review Included in this posting are a clean version of the affected VSLs and a redline version of the VSLs compared to thecurrent FERC-approved VSLs The documents have been posted for a 30-day concurrent formal comment period that will end at 8 pmEST on February 17 2010 The non-binding poll will take place during the last ten days of this period beginning at 8 am EST onFebruary 9 2010 Ballot Pool Open through 8 am on February 9 2011During the last set of ballots for VSLs six separate ballot pools were formed To simplify the process for balloting the current set of revisedVSLs a single ballot pool has been formed and members of the TPL VSL ballot pool (the largest of the 6 previous ballot pools) have beenpre-registered for the new VSL ballot pool Each of these preregistered members will receive an email indicating that they have been pre-registered for this new ballot pool and notice that they may drop out of the ballot pool if they donrsquot wish to participate in this new non-binding poll In addition during the first 20 days of the 30-day comment period any member of the Registered Ballot Body may join the new ballot poolto be eligible to vote in the upcoming ballot at the following page httpsstandardsnercnetBallotPoolaspx During the pre-ballot window members of the ballot pool may communicate with one another by using their ldquoballot pool list serverrdquo (Once the balloting begins ballot pool members are prohibited from using the ballot pool list servers) The list server for this ballot pool isbp-2007-23_VSL_NB_innerccom Comment Period Open through 8 pm on February 18 2011Please use this electronic form to submit comments If you experience any difficulties in using the electronic form please contact MonicaBenson at monicabensonnercnet An off-line unofficial copy of the comment form is posted on the project pagehttpwwwnerccomfilezstandardsVSLs_Project_2007-23html Next StepsA non-binding poll of the revised VSLs will take place during the last ten days of this period beginning at 8 am EST on February 9 2010 Project BackgroundIn a June 2008 order FERC directed NERC to review all VSL assignments for compliance with certain guidelines and to submit acompliance filing either justifying the current VSL assignments or proposing revisions Proposed VSLs were balloted in 2009 and a revisedproposed set of VSLs was filed with FERC on March 5 2010 In December 2010 NERC and FERC staffs met to discuss 14 sets of VSLs in need of modification In some cases changes were neededfor clarity and in other cases there was a need to modify a VSL to ensure compliance with FERCrsquos VSL Guidelines In coordination with members of the VSL DT for Project 2007-23 NERC staff made changes to ensure clarity and compliance with FERCGuidelines and these changes have been posted here for industry review Standards Development ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate For moreinformation or assistance please contact Monica Benson at monicabensonnercnet






From Monica BensonTo monicabensonnercnetSubject Standards Announcement Results of Non-Binding Poll of VSLs | Project 2007-23 Violation Severity LevelsDate Monday March 07 2011 40256 PM

Standards AnnouncementResults of Non-Binding Poll of VSLsProject 2007-23 ndash Violation Severity Levels Now available at httpwwwnerccomfilezstandardsVSLs_Project_2007-23html

A non-binding poll of proposed revisions to 14 sets of VSLs closed on February 22 2011 Of those who registered to participate 78provided an opinion 72 of those who provided an opinion indicated support for the VRFs and VSLs that were proposed The VSLs have been revised to incorporate feedback from the non-binding poll and the revised VSLs along with redlines to last postedand last approved and a comment report have been posted on the project page Next StepsThe revised VSLs will be presented to the Board of Trustees for approval Project BackgroundIn a June 2008 order FERC directed NERC to review all VSL assignments for compliance with certain guidelines and to submit acompliance filing either justifying the current VSL assignments or proposing revisions Proposed VSLs were balloted in 2009 and a revisedproposed set of VSLs was filed with FERC on March 5 2010 In December 2010 NERC and FERC staffs met to discuss 14 sets of VSLs in need of modification In some cases changes were neededfor clarity and in other cases there was a need to modify a VSL to ensure compliance with FERCrsquos VSL Guidelines In coordination with members of the VSL DT for Project 2007-23 NERC staff made changes to ensure clarity and compliance with FERCGuidelines and these changes were posted for industry review from January 20 2011 through February 22 2011 Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Guy V ZitoTo rsballotCc rscSubject FW Please Cast Your Vote Today for the Relay Loadability Order 733 Ballot | Project 2010-13Date Friday February 11 2011 41910 PMImportance High

NPCC Members of the NERC Registered Ballot Body The RSC has conducted a review and sought technical opinion on the subject referenced ballot currently underway through February 132011 The primary issues raised at the last ballot were addressed and the TFSP has identified no further dealbreakers The RSCsupermajority is recommending a vote to Accept the standard Some of the RSC members will be submitting comments with theiraffirmative ballots and one member will be submitting a negative vote with a comment indicating that further clarification are needed anda previous comment was not sufficiently responded to Based on the technical recommendation of the TFSP and the majority of RSCs affirmative recommendation NPCC will be votingaffirmative to accept the standard and accept the VSLs Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica Benson [MonicaBensonnercnet]Sent Thursday February 10 2011 913 AMTo bp-2010-13_rlo_sb_inSubject Please Cast Your Vote Today for the Relay Loadability Order 733 Ballot | Project 2010-13

Dear Relay Loadability Order 733 Ballot Pool Members

The Successive Ballot to vote on the proposed changes to PRC-023-2 - Transmission Relay Loadability and the non-binding poll of theVRFs and VSLs for PRC-023 will both end soon We have not achieved quorums on either of these two standard actions If youhave not cast your vote on the standard or if you have not submitted your opinion on the VRFs and VSLs please help usachieve quorums by doing so as soon as possible You can log in and cast your votes from the following page httpsstandardsnercnetCurrentBallotsaspx

Maureen E LongDirector Standards Process813-468-5998 Regards

Monica Benson (sent on behalf of Maureen Long)Standards Process AdministratorNorth American Electric Reliability Corporation116-390 Village BlvdPrinceton NJ 08540404-446-2560 ext 573wwwnerccom

---Y

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Project 2010-13 - Relay Loadability Order 733 ModificationsDate Monday January 24 2011 60018 PM

Standards AnnouncementSuccessive Ballot and Non-binding Poll OpenProject 2010-13 ndash Relay Loadability Order 733 ModificationsJanuary 24-February 13 2011 Now available at httpsstandardsnercnetCurrentBallotsaspx Project 2010-13 Revisions to Relay Loadability for Order 733PRC-023-2 mdash Transmission Relay Loadability has been posted for a 20-day successive ballot of the proposed standard and its associatedimplementation plan through 8 pm on February 13 2011 A non-binding poll of the associated Violation Risk Factors (VRFs) andViolation Severity Levels (VSLs) will be conducted during the same time Registered Ballot Body members who joined the ballot pool to vote on the standard have already been automatically entered in a separatepool to participate in the non-binding poll for the VRFs and VSLs For ballot pool members the non-binding poll appears in the list ofcurrent ballots and is labeled accordingly InstructionsMembers of the ballot pools associated with this project may log in and submit their votes from the following pagehttpsstandardsnercnetCurrentBallotsaspx BackgroundThis standard was revised to address a set of directives in Order 733 and must be submitted to FERC by March 18 2011 To meet thisdelivery date the Standards Committee authorized use of the expedited standard development process Under the expedited standarddevelopment process the Standards Committee may alter certain steps in the standard development process to meet a regulatory deadline In this case the Standards Committee authorized the drafting team to conduct successive ballots without parallel comment periods Toallow stakeholders time to review the changes made between ballots the Standards Committee authorized an extended ballot window of 20calendar days rather than 10 calendar days Next StepsVoting results will be posted and announced after the ballot windows close Project BackgroundWhen FERC issued Order 733 approving PRC-023-1 mdashTransmission Relay Loadability it directed several changes to that standard andalso directed development of one or more new standards within specified time periods NERC filed for clarification and rehearing askingfor clarity and an extension of time to address the directives however without a response to the requests for clarification and rehearingNERC must proceed as though these requests will be deniedThe SAR for Project 2010-13 subdivides the standard-development-related directives into three phases Phase I addresses the specificdirectives from Order 733 that identified required modifications to various elements within PRC-023-1 Phase II addresses directivesassociated with development of a new standard to address generator relay loadability Phase III addresses directives associated with writingrequirements to address protective relay operations due to power swings More information on this project may be found on the project pagehttpwwwnerccomfilezstandardsSAR_Project202010-13_Order2073320Relay20Modifiationshtml Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Monica BensonTo monicabensonnercnetSubject Standards Announcement Project 2010-13 Relay Loadability for Order 733 - Successive Ballot ResultsDate Wednesday February 16 2011 35414 PM

Standards AnnouncementSuccessive Ballot ResultsProject 2010-13 - Relay Loadability for Order 733 Now available at httpsstandardsnercnetBallotsaspxA successive initial ballot of PRC-023-2 mdash Transmission Relay Loadability ended on February 14 2011 Voting statistics are listed belowand the Ballot Results Web page provides a link to the detailed results Ballot for Standard

middot Quorum 8395middot Approval 6571

Violation Risk Factor (VRF) and Violation Severity Level (VSL) Non-binding Poll Results

middot The poll achieved a quorum with 80 of those who registered to participate provided an opinion 65 of those who provided anopinion indicated support for the VRFs and VSLs that were proposed

Project BackgroundWhen FERC issued Order 733 approving PRC-023-1 mdash Transmission Relay Loadability it directed several changes to that standard andalso directed development of one or more new standards within specified time periods NERC filed a request for clarification andrehearing and requested additional time to address the directives however pending FERCrsquos response to the requests for clarification andadditional time NERC must progress as though these requests will be denied The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases Phase I addresses the specificdirectives from Order 733 that identified required modifications to various elements within PRC-023-1 Phase II addresses directivesassociated with development of a new standard to address generator relay loadability Phase III addresses directives associated with writingrequirements to address protective relay operations due to power swings More details may be found on the project pagehttpwwwnerccomfilezstandardsSAR_Project202010-13_Order2073320Relay20Modifiationshtml

Next StepsThe drafting team will consider all comments (those submitted with a comment form and those submitted with a ballot) and will determinewhether to make additional changes to the standard The team will post its response to comments and if the standard has only minorchanges will post the standard and conduct a 10-day recirculation ballot Ballot CriteriaApproval requires both (1) a quorum which is established by at least 75 of the members of the ballot pool submitting either anaffirmative vote a negative vote or an abstention and (2) a two-thirds majority of the weighted segment votes cast must be affirmative thenumber of votes cast is the sum of affirmative and negative votes excluding abstentions and non-responses






116-390 Village Blvd Princeton NJ 08540 6094528060 | wwwnerccom

TO NERC Board of Trustees FROM David Cook

Senior Vice President amp General Counsel DATE March 9 2011 SUBJECT Update to Ballot Results for Reliability Standards Development Plan (Agenda

Item 1a) and Proposed PRC-023-2 Reliability Standard (Agenda Item 1d) The purpose of this memo is to update the members of the NERC Board of Trustees on

(1) The final results of the Standards Committee email ballot of the proposed Reliability Standards Development Plan 2011-2013 and

(2) The final ballot results for the proposed PRC-023-2 ndash Transmission Relay Loadability Reliability Standard which closed on March 7 2011

Agenda Item 1a Standards Committee Email Ballot of Reliability Standards Development Plan 2011-2013 The Standards Committee email ballot of the updated Reliability Standards Development Plan 2011-2013 concluded on March 3 with 17 of the 19 Standards Committee members submitting votes Fifteen Standards Committee members voted affirmatively for the revised plan There were two abstentions which meets the required 23 affirmative vote for passage A complete listing of the final Standards Committee voting record is included for reference NERC management recommends board approval of the proposed Reliability Standards Development Plan 2011-2013 Agenda Item 1d Ballot Results for PRC-023-2 A Recirculation Ballot of the PRC-023-2 Transmission Relay Loadability Reliability Standard and its associated implementation plan closed on March 7 2011 The ballot achieved a quorum of 8735 and a weighted segment approval of 6883 thereby passing the industry ballot process A Non-binding poll of the standardrsquos Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) was also conducted and achieved a quorum of 80 and an average approval of 65 The low approval is attributed to the number of requirements that were considered ldquobinaryrdquo resulting in a single Severe VSL for five of the six requirements In proposing VRFs and VSLs the drafting team proposed VRFs and VSLs that aligned with those approved by FERC in Order 733 NERC management recommends board approval of the proposed PRC-023-2 standard its associated implementation plan and its associated VRFs and VSLs for filing with FERC

-2-

Standards Committee Email Ballot Results for RSDP 2011-13

(224 ndash February 24 2011) (32 ndash March 2 2011) (33 ndash March 3 2011)

Affirmative Negative Abstain Comments

Segment 1-2010-11 Carol A Sedewitz X (32)

Segment 1-2010-12 Jason Shaver X (33)

Segment 2-2010-11 PS (Ben) Li X (32)

Segment 2-2011-12 Patrick Brown X (32)

Segment 3-2011-12 Ronald G Parsons X (32)

Segment 4-2010-11 Allen Mosher X (33)

Segment 4-2011-12 Joseph Tarantino X (32)

Segment 5-2011-12 Michael F Gildea X (32)

Segment 6-2010-11 Alice Murdock Ireland X (32)

Segment 6-2011-12 Silvia Parada Mitchell X (33)

Segment 7-2010-11 Frank McElvain X (33)

Segment 7-2011-12 John A Anderson X (32)

Segment 8-2010-11 Jim R Stanton X (224)

Segment 8-2011-12 Michael Goggin

Segment 9-2010-11 Klaus Lambeck X (32)

Segment 9-2011-12 Diane J Barney X (32)

Segment 10-2010-11 Linda Campbell X (32)

Segment 10-2011-12 Steve Rueckert X (32)

Canada Robert Blohm








---Y

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Recirculation Ballot Window Open February 24 - March 6 2011 | Project 2010-13Date Thursday February 24 2011 32601 PM

Standards AnnouncementRecirculation Ballot Window OpenProject 2010-13 ndash Relay Loadability Order 733February 24-March 6 2011 Now available at httpsstandardsnercnetCurrentBallotsaspx Project 2010-13 ndash Relay Loadability Order 733A recirculation ballot for PRC-023-2 ndash Transmission Relay Loadability is open until 8 pm (Eastern) on March 6 2011 InstructionsMembers of the ballot pool associated with this project may log in and submit their votes from the following pagehttpsstandardsnercnetCurrentBallotsaspxIn the recirculation ballot votes are counted by exception Only members of the ballot pool may cast a ballot all ballot pool members maychange their prior votes A ballot pool member who failed to cast a ballot during the last ballot window may cast a ballot in therecirculation ballot window If a ballot pool member does not participate in the recirculation ballot that memberrsquos last vote cast in thesuccessive ballot that ended on February 14 2011 will be carried over and used to determine if there are sufficient affirmative votes for thisstandard to pass This is an extremely important ballot as NERC is responding to a set of FERC directives that require submitting modifications to PRC-023-1 by March 18 2011 We encourage all members of the ballot pool to review the revised standard and the drafting teamrsquos consideration ofthe comments submitted with the last ballot The team made the following changes following the initial ballot in support of stakeholdercomments

Modified the applicability to clarify that the transmission lines and transformers that must have protection compliant with the standardare limited to those that are part of the BES and are selected by the Planning Coordinator (Previously the applicability did not includethe phrase ldquopart of the BESrdquo)Reformatted the presentation of the effective dates so that the dates are easier to comprehend

Corrected footnote 5

Revised M4 and M5 to clarify that attestations are acceptable forms of evidence

Added another Severe VSL for R6 to cover the situation where an entity is totally noncompliant with the requirement

Changed ldquosupervisory elementsrdquo to ldquoPhase overcurrent supervisory elementsrdquo for clarity in Attachment A

The drafting team will be holding a webinar to review the modifications made to the standard on Wednesday March 2 from 1-2 pm(Eastern) The Standards Committee encourages all ballot body members to participate in this webinar Next StepsVoting results will be posted and announced after the ballot window closes This standard is scheduled to be submitted to the Board ofTrustees on March 10 2011 and filed for regulatory approval by March 18 2011 Project BackgroundWhen FERC issued Order 733 approving PRC-023-1 mdashTransmission Relay Loadability it directed several changes to that standard andalso directed development of one or more new standards within specified time periods NERC filed for clarification and rehearing asking forclarity and an extension of time to address the directives and the extension was granted but only applies to one of the directives NERC isstill required to file a revised standard that addresses several directives from Order 733 by March 18 2011The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases Phase I addresses the specificdirectives from Order 733 that identified required modifications to various elements within PRC-023-1 Phase II addresses directivesassociated with development of a new standard to address generator relay loadabilty Phase III addresses directives associated with writingrequirements to address protective relay operations due to power swings Further details are available on the project pagehttpwwwnerccomfilezstandardsSAR_Project202010-13_Order2073320Relay20Modifiationshtml Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERC

standards development process depends on stakeholder participation We extend our thanks to all those who participate






From Monica BensonTo monicabensonnercnetSubject Standards Announcement Project 2010-13 ndash Relay Loadability Order | Recirculation Ballot ResultsDate Tuesday March 08 2011 25433 PM

Standards AnnouncementProject 2010-13 ndash Relay Loadability OrderRecirculation Ballot Results Now available at httpsstandardsnercnetBallotsaspx Ballot Results for Revisions to PRC-023A recirculation ballot on revisions to PRC-023 Transmission Relay Loadability concluded on March 7 2011 The revised standard PRC-023-2 was approved by the ballot pool Voting statistics are listed below and the Ballot Results Web page provides a link to the detailed resultsQuorum 8735Approval 6883 Next StepsPRC-023-2 will be presented to the NERC Board of Trustees for adoption and filed with regulatory authorities

BackgroundAs the ERO NERC must address all directives in Orders issued by FERC On March 18 2010 FERC issued Order No 733 whichapproved Reliability Standard PRC-023-1 ndash Transmission Relay Loadability and also directed NERC as the Electric ReliabilityOrganization (ldquoEROrdquo) to develop certain modifications to the PRC-023-1 standard through its Reliability Standards development processto be completed and filed with the Commission by March 18 2011 Attachment 1 to the SAR contains the directives and associateddeadlines The Order also directed development of two new Reliability Standards to address issues related to generator relay loadability andthe operation of protective relays due to power swings The standards-related directives in Order 733 are aimed at closing some reliability-related gaps in the scope of PRC-023-1

The SARrsquos scope includes three standard development phases to address the standards-related directives in Order No 733 directives PhaseI is focused on making the specific modifications to PRC-023-1 that were identified in the order Phase II is focused on developing a newstandard to address generator relay loadability and Phase III is focused on developing requirements that address protective relay operationsdue to power swings

Further details are available on the project page httpwwwnerccomfilezstandardsSAR_Project202010-13_Order2073320Relay20Modifiationshtml Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






Unofficial Comment Form for Standards Committeersquos Project Prioritization Reference Document and Tool Please do not use this form to submit comments on the draft standard prioritization tool and associated reference document Please use the electronic comment form to submit your comments Comments must be submitted by February 10 2011 If you have questions please contact Maureen Long at maureeenlongnercnet or by telephone at 813-468-5998


The Standards Committee has posted a draft standard project prioritization tool and reference document (Standards Committee Process for Standard Project Identification Prioritization and Monitoring) proposed for use in prioritizing standard projects Comments will be accepted through February 10 2011

During the past few years the Standards Committee has been presented with more proposals for developing new or revised projects than can be accomplished at one time The project prioritization tool is an excel spreadsheet that provides a transparent method of identifying the reliability-related benefits associated with each standard development project The tool provides the flexibility to accommodate new projects and to adjust project priorities and completion schedules in response to changing conditions and will be used to assign a priority to each standard project proposed for development

The reference document provides an explanation of the project prioritization tool and identifies how the Standards Committee envisions using the tool

You are encouraged to read the reference document and then review the tool and the ratings assigned to each of the proposed projects

We ask that you provide comments on the tool and then comments on the initial set of ratings If you disagree with the rating assigned to a specific project please identify why you believe the rating is incorrect and identify what rating you believe is more appropriate Please be as specific as possible to help the Standards Committee in making adjustments to the ratings already assigned For example if you believe that the proposed project will fill a reliability gap that is not properly rated identify the reliability gap that is addressed in the project

You do not have to answer all questions Enter All Comments in Simple Text Format

Insert a ldquocheckrdquo mark in the appropriate boxes by double-clicking the gray areas

Standards Committee Process for Standard Project Identification Prioritization and Monitoring 1 Please provide any comments you have on the draft reference document

Comments Oftentimes prioritization of projects relies on experience engineering and technical judgment This tool and reference document provide useful and helpful guidance to the Project Prioritization activity bringing objectivity to what can be a very subjective process Refer also to question 8 below

Project Prioritization Tool

2 Do you agree with the range of questions (column headings) in the tool

Yes

No

Comments

3 Do you agree that the range (0-100) for the red and orange columns in the tool

Yes

No

Comments The range in Red Column ldquogrdquo is 0 to 50 Otherwise agree

4 Do you agree that the range (0-50) for four of the yellow columns with the column identifying the investment already made in the project rated with a possible rating of 0-100

Yes

No

Comments 5 Do you agree that the range (0-100) for the blue column in the tool

Yes

No

Comments 6 What factors do you believe the Standards Committee should consider in the ldquoOtherrdquo

column

Yes

No

Comments The ldquoExplanationrdquo column ldquoprdquo allows room for explanations of the lsquoOtherrdquo column

Proposed Ratings for Projects Included in the Reliability Standard Development Plan

7 Please review the ratings assigned to each of the individual projects If you feel that any of the draft ratings are inaccurate please identify the project number and the specific rating that you believe is inaccurate Please be specific in identifying what you believe is the correct rating and provide a justification for that proposed rating

Comments

8 Please provide any other comments you feel would be beneficial to the Standards Committee in making improvements to the reference document and project prioritization tool

Comments In NERCrsquos 2011 Plan there are 17 Priority Standards identified This exceeds the resources available quoting from p 5 Section 3 ldquoRecent Standards Committee and NERC staff experience generally supports the conclusion that NERC and the industry can manage the development of no more than ten to twelve standards projects under active development at any one time hellip our informed judgment is that attempts to develop more than ten or twelve projects during the same period will result in an actual loss of throughput andor a reduction in standards qualityrdquo There are no explanations supporting the scoring values Why is one criteria worth 10 while another 25 or 100 Weighted Criteria-Based Scoring Systems for Project Management under Resource Constraints are widely used to select and prioritize projects Generally the projected sum-of-the-projects results are indicative of some bottom-line measure like impact on profits Here the bottom-line impact on reliability is only indirectly indicated through the very qualitative unsupported values assigned to the various criteriameasures eg 10 25 or 100 Shouldnrsquot some more quantitative Reliability measure be used for scoring such as some threshold improvement in LOLP or a minimum benefitcost ratio eg 121 Why are certain cells highlighted yellow in the body of the Prioritization Tool

116-390 Village Boulevard Princeton New Jersey 08540-5721

Phone 6094528060 Fax 6094529550 wwwnerccom

Unofficial Comment Form for BAL-003-1 Frequency Response and Frequency Bias Standard Please DO NOT use this form to submit comments on the 1st draft of BAL-003-1 ndash Frequency Response and Frequency Bias Setting Comments must be submitted by March 7 2011 If you have questions please contact Darrel Richardson by email at darrelrichardsonnercnet or by telephone at 6096131848


Frequency Response a measure of an Interconnectionrsquos ability to stabilize frequency immediately following the sudden loss of generation or load is a critical component to the reliable operation of the bulk power system particularly during disturbances and restoration The proposed standardrsquos intent is to collect data needed to accurately analyze existing Frequency Response set a minimum Frequency Response obligation provide a uniform calculation of Frequency Bias Settings that transition to values closer to Frequency Response and encourage coordinated AGC operation There is evidence of continuing decline in Frequency Response over the past 10 years but no confirmed reason for the apparent decline The proposed standard requires entities to provide data so that Frequency Response in each of the Interconnections can be analyzed and the reasons for the decline in Frequency Response can be identified Once Frequency Response has been analyzed and confirmed requirements can be modified to maintain reliability

The Drafting Team would like to receive industry comments on this standard Please submit your comments using the electronic form by March 7 2011



1 The SDT has developed three new terms to be used with this standard

Single Event Frequency Response Data (SEFRD)

The individual sample of event data from a Balancing Authority which represents the change in Net Actual Interchange (NIA) divided by the change in frequency expressed in MW01Hz

Frequency Response Measure (FRM)

The median of all Single Event Frequency Response Data observations reported annually on FRS Form 1

Frequency Response Obligation (FRO)

The Balancing Authorityrsquos contribution to the total aggregate Frequency Response needed for reliable operation of an Interconnection assigned by the ERO

Comment Form mdash BAL-003-1 Frequency Response amp Frequency Bias Standard

Page 2 of 7

Do you agree with the proposed definitions in this standard If not please explain in the comment area

Yes

No

1 Comments

2 The SDT has modified the definition for the term Frequency Bias Setting The new definition is shown below in redline to show the changes proposed

Frequency Bias Setting

A value (either a fixed or variable Frequency Bias) usually expressed in MW01 Hz set into a Balancing Authority Area Control Error algorithm equation that allows the Balancing Authority to contribute its frequency Frequency rResponse to the Interconnection

Do you agree with this new definition for Frequency Bias Setting If not please explain in the comment area

Yes

No

2 Comments

3 The proposed purpose statement in the draft standard is

To require sufficient Frequency Response from the Balancing Authority to maintain Interconnection Frequency within predefined bounds by arresting frequency deviations and supporting frequency until the frequency is restored to schedule To provide consistent methods for measuring Frequency Response and determining the Frequency Bias Setting

Do you agree with this purpose If not please explain in the comment area

Yes

No

Comments

4 Requirement 1 identifies a minimum level of Frequency Response

R1 Each Balancing Authority shall achieve a Frequency Response Measure (FRM) (as detailed in Attachment A and calculated on FRS Form 1) that is equal to or more negative than its Frequency Response Obligation (FRO)

Do you agree with the concept that a Balancing Authority should be required to achieve a minimum level of Frequency Response and the method for measurement If not please explain in the comment area

Yes

No

Comments


Page 3 of 7

5 Requirement 2 identifies when the Balancing Authority must implement its Frequency

Bias Setting

R2 Each Balancing Authority shall implement the Frequency Bias Setting (fixed or variable) provided by the ERO into its Area Control Error (ACE) calculation beginning on the date specified by the ERO to ensure effective coordinated secondary control using the results from the calculation methodology detailed in Attachment A

Do you agree with this implementation If not please explain in the comment area

Yes

No

Comments

6 Requirement 3 mandates that a Balancing Authority operate its Automatic Generation

Control (AGC) on Tie Line Bias unless it becomes adverse to the integrity of its system

R3 Each Balancing Authority shall operate its Automatic Generation Control (AGC) on Tie Line Bias unless such operation would have an Adverse Reliability Impact on the Balancing Authorityrsquos Area

Do you agree that a Balancing Authority should operate its AGC on Tie Line Bias unless it becomes adverse to its system If not please explain in the comment area below

Yes

No

Comments

7 Do you agree with the proposed Implementation Plan for this standard If not please

explain in the comment area

Yes

No

Comments

8 This standard proposes to eliminate the 1 minimum Frequency Bias over a period of 4 years as outlined in the Implementation Plan Do you agree that the elimination of the 1 minimum will bring Frequency Bias closer or equal to natural Frequency Response If not please explain in the comment area

Yes

No

Comments


Page 4 of 7

9 Do you agree with the drafting team that this standard should be field tested If not please explain in the comment area

Yes

No

Comments

10 Attachment A of the proposed standard describes the criteria for selecting events to be

analyzed Do you agree with the criteria as described in Attached A If not please explain in the comment area

Yes

No

Comments

11 The proposed standard has a document attached to it that describes the SDTrsquos reasoning for the Requirements (Attachment A - Frequency Response Background Document) Do you agree with the SDT that this document is useful and provides a clear understanding of the Requirements If not please explain in the comment area

Yes

No

Comments

12 The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authorityrsquos FRM Do you agree with the SDT that this is the proper method to calculate its FRM If not please explain in the comment area and if possible provide an alternate method to calculate FRM

Yes

No

Comments

13 The proposed standard requires the use of FRS Form 1 for calculating a Balancing Authorityrsquos Frequency Bias Setting Do you agree with the SDT that this is the proper method to calculate its Frequency Bias Setting If not please explain in the comment area and if possible provide an alternate method to calculate Frequency Bias Setting

Yes

No

Comments

14 The SDT has provided a document (FRS Form 1 Instructions) describing how to use FRS Form 1 for calculating FRM and Frequency Bias Setting Do you agree with the SDT that this document provides a clear understanding of how to use the form If not please explain in the comment area

Yes

No


Page 5 of 7

Comments

15 The SDT is soliciting comments on methods of obtaining Frequency Response to meet the FERC Order 693 directive If possible please provide any thoughts you may have on this subject Comments

16 If you are aware of any conflicts between the proposed standard and any regulatory function rule order tariff rate schedule legislative requirement or agreement please identify the conflict here

Comments

17 Please provide any other comments (that you have not already provided in response to

the questions above) that you have on the draft standard BAL-003-1

Comments It is not clear from either Form 1 or its instructions whether the supplied frequency deviation for an event should be used without modification or if it should be overwritten with a value computed from the Balancing Authorityrsquos data source (or if there is an option to use the lesser value for example) Clearly express which frequency deviation value to use The load sensitivity calculation is an important Balancing Authority Area value to compute accurately for modeling purposes As proposed it would use the same computational technique as that used for frequency bias sampling calculations To yield a useful result load values would need to have ldquoconvergence characteristicsrdquo similar to that found in the actual net interchange values used for frequency bias sampling While experience has shown that the average or median values of the frequency bias samples computed for most Balancing Authorities will converge with about 20 samples a similar outcome for load sensitivity calculations might not occur Frequency bias samples rely on the measured actual net interchange values that are sampled at the AGC scan rate and the actual net interchange tends to be a rather stable value because AGC and operator actions usually keep the actual net interchange close to a scheduled value The total net system load may have greater volatility and may be trending in a particular direction much more often than actual net interchange Also the load calculation typically relies on adding the sum of the generation within the Balancing Authority to the actual net interchange The generation values may have a slower scan rate longer data latency periods and smaller generators might not be telemetered with hourly scheduled values or manually entered values being used instead These differences can contribute to a very different convergence characteristic than that found for actual net interchange Simply put the load sensitivity calculation needs validation


Page 6 of 7

The Form 1 instructions mention a generation only Balancing Authority form to be filled in It is not shown on the spreadsheet provided and it is not clear what data should be entered though it seems like it would still be actual net interchange

Form 1 contains an entry form for a single Balancing Authority Interconnection however it is not referenced in the Form 1 instructions Section A of the Form 1 instructions contains excellent background material that explains why this effort is important However section B needs a careful review so that the instructions are thorough and unambiguous

The information on variable bias calculations seems sparse and the requirements for variable bias should be reviewed thoroughly with those Balancing Authorities that are familiar with the nuances and challenges of determining an appropriate variable bias If BIAS is set equal to response about 50 of the time AGC will cancel out the primary response the BIAS therefore should be slightly higher than the natural response but clearly 1 is too large The game plan to continually reduce the floor percentage for frequency bias settings needs to be reconsidered With 4 peak load being a typical actual frequency response lately for Balancing Authorities the 1 of peak load to 8 of peak load transition seems prudent Perhaps a further reduction to 6 may be useful as well but lesser floors may in effect result in AGC too often canceling out the primary frequency response being provided While the 16 to 52 second sampling window for point B computations seem to be a reasonable initial guess for the metric preliminary studies by the Frequency Responsive Reserve Standard Drafting Team (FRRSDT) indicate that AGC contributions from fast acting hydro generators will be included in the samples As those same studies were not conclusive perhaps the initial years of this standard could require the provision of scan rate data from 30 seconds before to 60 seconds after the start of the frequency decline for each event While this significantly increases the volume of data to be provided it would allow the FRRSDT to determine the best sampling intervals to be used Perhaps a point B sampling interval of 15 to 30 seconds would filter out most of the fast acting AGC but more dataanalysis is needed to determine the best sampling interval to be sure that the primary response data is not being corrupted by this fast acting AGC response

To support Balancing Authorities in achieving the targeted level of frequency response a standard for generators is needed as well as they are historically the largest source of discretionary frequency response The standard could give a Balancing Authority the right to waive these requirements should they pursue other sources of frequency response such as ERCOTrsquos ldquoload acting as a resource (LAAR)rdquo efforts


Page 7 of 7

Point C values are the more important reliability metric Since point C metrics are challenged with data quality issues on a Balancing Authority and generator level an effort should be made to correlate the required frequency response in the point B time window with that needed in the point C time window (perhaps using rules of thumb such as 100 of loadrsquos frequency response and 30 of generatorrsquos frequency response occurs in time for point C)

While Attachment A mentions that N-2 category C events will be used to determine the frequency response obligation on an interconnection level there is insufficient detail provided at this time to evaluate the appropriateness of the obligations selected Efforts in this area for the frequency model developed by the Reliability-Based Control Standard Drafting Team (and now the BARCSDT) for HQTE may shed some insight into this process

















Page 2 of 7


Yes

No

1 Comments





Yes

No

2 Comments




Yes

No

Comments




Yes

No

Comments


Page 3 of 7


Bias Setting



Yes

No

Comments





Yes

No

Comments



Yes

No

Comments


Yes

No

Comments


Page 4 of 7


Yes

No

Comments



Yes

No

Comments


Yes

No

Comments


Yes

No

Comments


Yes

No

Comments


Yes

No


Page 5 of 7

Comments



Comments





Page 6 of 7






Page 7 of 7





Official Comment Form for Project 2007-23 mdash Violation Severity Levels Please DO NOT use this form Please use the electronic comment form to submit comments on the proposed revisions to 14 sets of VSLs Comments must be submitted by February 18 2011 If you have questions please contact Mallory Huggins at malloryhugginsnercnet or by telephone at 609-619-1629

Individual Commenter Information

(Complete this page for comments from one organization or individual)

Name

Organization

Telephone

E-mail NERC Region Registered Ballot Body Segment

ERCOT FRCC MRO NPCC RFC SERC SPP WECC NA ndash Not Applicable

1 mdash Transmission Owners 2 mdash RTOs and ISOs 3 mdash Load-serving Entities 4 mdash Transmission-dependent Utilities 5 mdash Electric Generators

6 mdash Electricity Brokers Aggregators and Marketers 7 mdash Large Electricity End Users 8 mdash Small Electricity End Users 9 mdash Federal State Provincial Regulatory or other Government Entities 10 mdash Regional Reliability Organizations and Regional Entities

Official Comment Form for Project 2007-23 mdash Violation Severity Levels

Page 2 of 6

Group Comments (Complete this page if comments are from a group)

Group Name Regional Standards Committee of the NPCC

Lead Contact

Contact Organization

Contact Segment

Contact Telephone

Contact E-mail If more than one Region or Segment applies indicate the best fit for the purpose of these comments Regional

acronyms and segment numbers are shown on prior page Additional Member Name Additional Member Organization Region Segment


Page 3 of 6

Background Information In its June 19 2008 VSL Order FERC directed NERC to review all Violation Severity Level (VSL) assignments ndash with the exception of those for which the Commission directed specific modification ndash for compliance with the following Guidelines 2b 3 and 4 and submit a compliance filing either validating the current VSL assignments or proposing revision

bull Guideline 2b mdash VSLs should not use ambiguous terms such as minor or significant to describe noncompliant performance

bull Guideline 3 mdash VSLs should be consistent with the corresponding requirement (VSLs should not expand on what is in the requirement)

bull Guideline 4 mdash VSLs should be based on a single violation not on a cumulative number of violations (unless stated otherwise in the requirement)

The VSL Drafting Team (VSL DT) posted the proposed VSLs1

for stakeholder comment from April 1-30 2009 The drafting team produced a redline version of each set of VSLs to show stakeholders the original set of VSLs that was balloted in 2008 the changes proposed by the VSL DT in April 2009 and additional changes made based on stakeholder comments in June 2009

The modifications made during this process were filed with FERC on March 5 2010 In December 2010 NERC and FERC staffs met to discuss 14 sets of VSLs in need of modification In some cases changes were needed for clarity and in other cases there was a need to modify a VSL to ensure compliance with FERCrsquos VSL Guidelines In coordination with members of the VSL DT for Project 2007-23 NERC staff made changes to ensure clarity and compliance with FERC Guidelines and these changes have been posted here for industry review A ballot pool from the last VSL comment period and nonbinding poll which took place from September 27 2010 through November 6 2010 has been cloned to create the ballot pool for this concurrent comment period and nonbinding poll Included in this posting are a clean version of the affected VSLs and a redline version of the VSLs compared to the current FERC-approved VSLs The documents have been posted for a 30-day concurrent formal comment and nonbinding poll period that will end at 8 pm EST on February 18 2010 The nonbinding poll will take place during the last ten days of this period beginning at 8 am EST on February 9 2010 NERC staff in coordination with the VSL Drafting Team will consider and respond to comments and make conforming changes where necessary The revised VSLs will be presented to the Board of Trustees for approval and then will be filed with applicable regulatory authorities Project page httpwwwnerccomfilezstandardsVSLs_Project_2007-23html

1 BAL-001 through BAL-006 CIP-001 COM-001 and COM-002 FAC-001 FAC-002 FAC-003 FAC-008 FAC-009 and FAC-013 INT-001 INT-003 through INT-010 IRO-001 through IRO-006 and IRO-014 through IRO-016 MOD-006 MOD-007 MOD-010 MOD-012 and MOD-016 through MOD-021 PER-001 through PER-004 NUC-001 PRC-001 PRC-004 PRC-005 PRC-007 through PRC-011 PRC-015 through PRC-018 PRC-021 and PRC-022 TOP-001 through TOP-008 TPL-001 through TPL-004 VAR-001 and VAR-002




You do not have to answer all questions Enter all comments in Simple Text Format

1 Do you agree with the proposed VSL(s) modifications for BAL-003-01b R1

If not please offer your suggested alternative language

Yes

No

Comments

2 Do you agree with the proposed VSL(s) modifications for COM-001-11 R2 If not please offer your suggested alternative language

Yes

No

Comments In the Severe VSL insert ldquotelecommunication facilitiesrdquo after ldquovitalrdquo to improve sentence clarity The High and Severe VSLs need to be clarified We understand ldquoemergency telecommunications facilities and equipment not used for routine communicationsrdquo to be a subset of ldquovital telecommunications facilitiesrdquo However as written the VSLs seem to treat these ldquoemergency telecommunications facilitiesrdquo as separate from the ldquovital telecommunications facilitiesrdquo If these emergency telecommunications facilities and equipment ARE considered vital we suggest removing the High VSL and in the Severe VSL replacing ldquoandrdquo before ldquoemergency telecommunications facilitiesrdquo with ldquoincludingrdquo


Yes

No

Comments Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement Suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of the main requirement For the High VSL replace ldquoallrdquo with ldquoat least onerdquo and make consequential changes to avoid a problem if some but not all entities were notified The text would read ldquofailed to notify at least one other potentially affected Balancing Authority or Transmission Operatorrdquo

4 Do you agree with the proposed VSL(s) modifications for FAC-003-1

R1221 If not please offer your suggested alternative language

Yes

No

Comments Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement Suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of the


Page 5 of 6

main requirement Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement Suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of the main requirement

5 Do you agree with the proposed VSL(s) modifications for IRO-004-1 R1 If

not please offer your suggested alternative language

Yes

No

Comments For the Severe VSL ldquoorrdquo should be replaced by ldquoORrdquo to make it clear that what follows is a second part to the VSL and ldquocontingencyrdquo (following ldquoorrdquo) should be capitalized



Yes

No

Comments For the Severe VSL replace ldquoreducingrdquo with ldquoreduction ofrdquo For the Severe VSL replace ldquoreducingrdquo with ldquoreduction ofrdquo



Yes

No

Comments For the Lower VSL we suggest replacing ldquoprovided after the required time (but not more than one hour after the required time)rdquo with ldquoprovided up to one hour after the required timerdquo For the Moderate VSL we suggest the sentence structure ldquomore than one hour and up to (and including) two hours after the required timerdquo A similar structure is suggested for the High VSL



Yes

No

Comments For consistency in language across all VSLs of this requirement ldquoinformationrdquo in the Moderate High and Severe VSLs should be changed to ldquoresultsrdquo We also suggest a sentence structure for the Lower Moderate and High VSLs similar to what was proposed in our response to Q7



Yes

No

Comments


Page 6 of 6

10 Do you agree with the proposed VSL(s) modifications for PRC-001-1 R1 If not please offer your suggested alternative language

Yes

No

Comments


Yes

No

Comments Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement We therefore suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of Requirement R32 into a set of VSLs for the main requirement Also for consistency with the other VSLs we suggest inserting ldquoeitherrdquo after ldquowithrdquo for the Severe VSL

12 Do you agree with the proposed VSL(s) modifications for PRC-001-1 R32 If


Yes

No

Comments Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement We therefore suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of the main requirement



Yes

No

Comments For the High VSL replace ldquowasrdquo with ldquowererdquo


Yes

No

Comments



Comment Form for Reliability Coordination ndash Project 2006-06 Please DO NOT use this form Please use the electronic comment form to submit comments on the proposed revisions to COM-001-2 IRO-001-2 IRO-002-2 and IRO-005-4 Comments must be submitted by March 7 2011 If you have questions please contact Stephen Crutchfield at stephencrutchfieldnercnet or by telephone at 609-651-9455



Name

Organization

Telephone

E-mail

NERC Region (check all Regions in which your company operates)

Registered Ballot Body Segment (check all industry segments in which your company is registered)

ERCOT

FRCC

MRO

NPCC

RFC

SERC

SPP

WECC

NA ndash Not Applicable

1 mdash Transmission Owners

2 mdash RTOs and ISOs

3 mdash Load-serving Entities

4 mdash Transmission-dependent Utilities

5 mdash Electric Generators

6 mdash Electricity Brokers Aggregators and Marketers

7 mdash Large Electricity End Users

8 mdash Small Electricity End Users

9 mdash Federal State Provincial Regulatory or other Government Entities

10 mdash Regional Reliability Organizations and Regional Entities

Comment Form mdash Reliability Coordination Project 2006-06

Page 2 of 7


Group Name IRC Standards Review Committee

Lead Contact Albert DiCaprio

Contact Organization PJM

Contact Segment ISO amp RTO

Contact Telephone 610 ndash 666 ndash 8854

Contact E-mail dicaprampjmcom

Additional Member Name Additional Member Organization

Region Segment

If more than one Region or Segment applies please list all that apply Regional acronyms and segment numbers are shown on prior page


Page 3 of 7


Based on comments received on the last posting the RCSDT has revised the proposed definitions in COM-001-2 as

Interpersonal Communication Any mediumthod that allows two or more individuals to interact consult or exchange information

Alternative Interpersonal Communication Any method Interpersonal Communication that is able to serve as a substitute for and is redundant to normal Interpersonal Communication and does not utilize the same infrastructure (medium) as normal Interpersonal Communications used for day-to-day operation

The RCSDT believes that these are better more concise definitions The RCSDT reviewed the Interpersonal Communications capability requirements (COM-001) and determined that there were implicit requirements within the requirements For example the requirement to identify an Alternative Interpersonal Communications capability implied that an entity had an interpersonal Communication capability Rather than leave these requirements implicit the RCSDT explicitly delineated by entity the requirements for Interpersonal Communications capability and Alternative Interpersonal Communications capability These explicit requirements are R1 through R8

Minor clarifying revisions were made to R2 and R3 of COM-002-2 and the words ldquoactual or expectedrdquo were removed from the proposed definition of Adverse Reliability Impacts The RCSDT believes that these conforming revisions indicate that consensus has been achieved with respect to COM-002-2

The RCSDT also is seeking stakeholder input with regard to a FERC Order 693 directive to consider Xcelrsquos comments relating to COM-002 The comment is as follows

Paragraph 523 ldquoNERC should consider Xcelrsquos suggestion that the entity taking operating actions should not be held responsible for the delays caused by the reliability coordinatorrsquos assessment and approval We note that the operating entity has the authority to take emergency actions to protect its system that may circumvent or preempt the reliability coordinatorrsquos approval process under TOP-001-1 Requirement R3 in cases of personnel safety potential equipment failure or environmental needsrdquo

The RCSDT agrees with FERC that an entity has the right and obligation to take action to prevent or mitigate emergencies etc Footnote 226 of Order 693 discusses TOP-001 requirements

Footnote 226 TOP-001-1 R1 states in part ldquoEach transmission operator shall have the responsibility and clear decision-making authority to take whatever actions are needed to ensure the reliability of its area helliprdquo and R2 states in part ldquoEach transmission operator shall take immediate actions to alleviate operating emergencies helliprdquo

The RCSDT believes that these requirements obviate the need to develop additional requirements to address Xcelrsquos comment

The RCSDT also met with FERC staff regarding the requirements contained in the proposed IRO-001 A suggestion was made to move some of the proposed requirements to IRO-002


Page 4 of 7

and IRO-005 as these requirements did not meet the purpose of the proposed IRO-001 standard The proposed IRO-001 standard is the ldquoumbrellardquo standard that established Reliability Coordinators and their authority The requirements that were subsequently re-inserted into IRO-002 and IRO-005 pertained to analysis tool outages and Reliability Coordinator notifications respectively

The drafting team also re-introduced into IRO-001 the requirement for regions to establish Reliability Coordinators The requirement is now applicable to Regional Entities and calls for the RE to ldquoensure at least one or more Reliability Coordinators is certified to continuously assess transmission reliability and coordinate emergency operations among the operating entities within the region and across the regional boundariesrdquo This requirement was originally proposed to be retired however after discussion with NERC legal staff the RCSDT proposed to retain the requirement and revise it as shown in the draft



1 Do you agree with COM-001 requirements for Interpersonal Communications capability and Alternative Interpersonal Communications capability (R1-R8) If not please explain in the comment area below

Yes

No Comments It was expressed in the last posting that the definition of Interpersonal Communications might inadvertently include data The SDT responded that it does not by referring to Interpersonal in the wording of the definition The word being defined shouldnrsquot be in the definition However incorporating ldquoallows two or more individuals to helliprdquo is an option that may solve this problem The next posting should clarify this This standard does not comport with the informational filing that NERC submitted to FERC on August 10 2009 regarding its discontinued use of sub-requirements in standards development activities The sub-requirements should be modified into bulleted lists Consider striking ldquoto exchange Interconnection and operating informationrdquo in R1 R3 R5 R7 and R8 It is redundant to the use of Interpersonal Communications ldquoto interact consult or exchange informationrdquo in the definition Consider striking ldquoto exchange Interconnection and operating informationrdquo in R2 R4 R6 It is redundant to the use of Alternative Interpersonal Communications which uses Interpersonal Communications in its definition Interpersonal Communications includes ldquoto interact consult or exchange informationrdquo in its definition For R2 why is Interchange Coordinator excluded It is included in the Requirement R1 which deals with the Interpersonal Communications Communications would need to be maintained with the Interchange Coordinator in the event of a failure of the Interpersonal Communications For R3 affected neighboring Transmission Operators should be included For R4 and R6 the sub-requirement list is different from the associated Interpersonal Communications requirements R3 and R5 respectively These should be duplicate The sub-requirement list for R4 should match R3 and the sub-requirement list for R6 should match R5 In the event of a failure of the Interpersonal


Page 5 of 7

Communications the Transmission Operator and Balancing Authority both would need to maintain communications to the same entities as in the requirement to have Interpersonal Communications The sub-requirements should be bulleted lists For R5 why are neighboring Balancing Authorities not included Additionally R5 should only read Contact with Interchange Coordinator within the same Interconnection They need to be able to contact one another to identify discrepancies in scheduling and sources of meter error that could lead to deviations in ACE Should R2 R4 and R6 be constructed parallel to R1 R3 and R5 In R1 R3 and R5 the requirement is ldquoshall haverdquo while in R2 R4 and R6 the requirement is ldquoshall designaterdquo Since one is for the Interpersonal Communications and the other is for the Alternative Interpersonal Communications the same wording should be used R22 and R12 should not be limited to Reliability Coordinators in the same Interconnection only Modify ldquowithin the same Interconnectionrdquo to ldquowithin the same Interconnection and as appropriate between a-synchronously connected RCs which are not precluded by law from scheduling interchange energy (for schedule changes curtailments etc)rdquo since reliability coordination may be required among the RCs on both sides of an Interconnection boundary The VSLs for R1 through R8 should be expanded to include multiple levels based on the number of entities that the functional entity does not have Interpersonal Communications or Alternative Interpersonal Communications with FERC specified their general preference for gradated in paragraph 27 of their June 19 2008 order on VSLs The second half of the Severe VSL for R9 is almost a duplicate of the Lower VSL There are some small changes in the wording but both situations deal with the case where there is a problem that has been identified with the Interpersonal Communications system and it takes more than two hours to initiate repair

2 The RCSDT believes that the requirements of TOP-001-1 obviate the need to develop additional requirements to address Xcelrsquos comment Do you agree If not please explain in the comment area below

Yes

No Comments If the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed to retire that requirement during their last posting There needs to be better coordination with that SDT

3 Do you agree with the revision to IRO-001 R1 for certifying Reliability Coordinators If not please explain in the comment area below

Yes

No Comments The language ldquoto continuously assess transmission reliabilityrdquo should be changed to ldquoto continuously assess Bulk Electric System reliabilityrdquo to reflect what the enforceability of the standards are meant to be The requirement on the ERO should also be expanded similar to BAL-005-01b R1 to ensure that all operating entities and the entire BES are covered under a Reliability Coordinator In R2 should ldquoofrdquo be ldquotordquo Reliability Directives are issued to TOPs BA etc The VSL for R1 is not consistent with the requirement The requirement applies to the ERO but the VSL applies to the Regional Entity


Page 6 of 7

4 Do you agree with moving two requirements from IRO-001 back to IRO-002 relating to Analysis Tool outages If not please explain in the comment area below

Yes

No

Comments

5 Do you agree with moving two requirements from IRO-001 back to IRO-005 relating to Reliability Coordinator notifications If not please explain in the comment area below

Yes

No Comments R1 states ldquoWhen the results of an Operational Planning Analysis or Real-time Assessment indicate an expected or actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area each Reliability Coordinator shall notify issue an alert to all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Areardquo The word ldquonotifyrdquo should be stuck

6 Do you have any other comment not expressed in questions above for the RC

SDT

Comments The SDT did not address all concerns with COM-002-3 from the last posting For entities registered as multiple functions the combination of the definition of Reliability Directive and Requirement R1 could be confused to require a company to issue directives to itself There are several organizations registered as a Reliability Coordinator Transmission Operator and Balancing Authority In these companies it is not uncommon for those responsibilities to be distributed across multiple desks Thus for certain situations a single System Operator may actually be the Reliability Coordinator and the Transmission Operator In other situations the System Operator serving the Reliability Coordinator function may be adjacent to the System Operator serving as the Transmission Operator or Balancing Authority It should never be necessary for these System Operators to issue Reliability Directives to themselves in the first example or to their co-worker in the second example to demonstrate compliance to NERC standards How the entity coordinates its actions among its Reliability Coordinator Balancing Authority and Transmission Operator roles is a corporate governance issue that should not be confused or complicated by the NERC standards Thus standards should be made clear that the Reliability Directive is directed to another company In place of requiring an operator in real-time to state ldquothis is a Reliability Directiverdquo there should be an allowance for an entity to develop procedures indicating in advance their expectations for three-part communications to their sub-operating entities Therefore we suggest modifying R1 to be ldquoWhen a Reliability Coordinator Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive the Reliability Coordinator Transmission Operator or Balancing Authority shall identify the action either verbally when the communication is issued or in advance through documented procedures as a Reliability Directive to the recipient [Violation Risk Factor High][Time Horizon Real-Time]rdquo Also the definition of Emergency as currently cited in these draft Standards and included in the existing NERC Glossary should be modified to include the NERC Glossary term Adverse Reliability Impact to make the Standards more crisp clear and enforceable Because the Project 2007-03 Real-Time Operations SDT proposed to utilize the definition of Adverse Reliability Impact in TOP-001-2 R5 during the last posting the change to the definition should be coordinated with that team


Page 7 of 7

There is a text box in IRO-005-4 that indicates this standard will be retired Yet there still remain requirements in the standard and various other associated documentation that indicates requirements are being move to this standard Delete the text box Strike IRO-014-2 Part 17 There is no need to have a weekly conference to discuss every Operating Procedure Operating Process and Operating Plan As this requirement is written a conference call would be necessary for each Furthermore IRO-014-2 R4 already includes a requirement to have weekly conference calls that should suffice IRO-014-2 R2 seems to recognize that these Operating Procedures Processes and Plans likely will not need to be discussed weekly as it only requires an annual update Requirement R2 in IRO-001 contains the words ldquowhich could include issuing Reliability Directivesrdquo but Reliability Directives are not referenced anywhere else in the standard This inclusion seems unnecessary since without it R2 already requires that the RC take actions or direct actions by others to prevent identified events or mitigate the magnitude or duration of actual events that result in Adverse Reliability Impacts Whether or not a Reliability Directive is issued is irrelevant in this requirement These words should be removed Note that COM-002 already stipulates the requirement for 3-part communication when a Reliability Directive is issued The inclusion of ldquowhich could include issuing Reliability Directivesrdquo in IRO-001 is unnecessary

From Lee R PedowiczTo cancommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject FW Draft CAN-0015 Unavailability of NERC ToolsDate Friday February 18 2011 51911 PM

Following are NPCCrsquos comments on CAN-0015

middot A CAN should not impose additional requirements middot It is important that a requirement is met not how you meet it middot If it is necessary to use a NERC tool to meet a requirement then it should be done that

way middot If changes are required then the NERC Standards Development process should be usedmiddot A CAN should only be used as a guideline

Lee PedowiczManager Reliability StandardsNPCC

From Lee R PedowiczTo cancommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject Draft CAN-0016 CIP-001-1 R1 - Applicability to Non-BESDate Friday February 18 2011 51753 PM


middot Having procedures and training to deal with sabotage to both BES and non-BES facilities isgood utility practice and should be encouraged However NERC and the Regions have nolegal authority to enforce the applicability of the reliability standards to non-Bulk ElectricSystem elements

middot Should not establish requirements for reporting on non-BES elements This is not the rightvenue for establish that requirement

middot CANs are for guidance not for establishing requirements on non-Bulk Electric Systemelements


From Lee R PedowiczTo cancommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject Draft CAN-0017 CIP-007 R5 System Access and Password ControlsDate Friday March 04 2011 81200 AMAttachments LP--Draft comments CAN-0017--3-4-11doc

Good morning Following are NPCCrsquos contributors to these comments and the comments on the subjectdocument (I also attached a Word version)

Member Organization Region SegmentSelection

1 Adamson Alan New York State Reliability Council LLC NPCC 10

2 Guy Zito Northeast Power Coordinating Council NPCC 10

3 Campoli Gregory New York Independent System Operator NPCC 2

4 Chong Kurtis Independent Electricity System Operator NPCC 2

5 Clermont Sylvain Hydro-Quebec TransEnergie NPCC 1

6 Dackow Bohdan M US Power Generating Company (USPG) NPCC ---

7 De Graffenried Chris Consolidated Edison Co of New York Inc NPCC 1

8 Dunbar Gerry NPCC NPCC 10

9 Evans-Mongeon Brian D Utility Services NPCC 8

10 Garton Mike Dominion Resources Services Inc NPCC 5

11 Gooder Brian L Ontario Power Generation Incorporated NPCC 5

12 Goodman Kathleen ISO - New England NPCC 2

13 Haswell Chantel FPL Group Inc NPCC 5

14 Kiguel David Hydro One Networks Inc NPCC 1

15 Lombardi Michael R Northeast Utilities NPCC 1

16 MacDonald Randy New Brunswick Power Transmission NPCC 1

17 Metruck Bruce New York Power Authority NPCC 6

18 Pedowicz Lee NPCC NPCC 10

19 Pellegrini Robert The United Illuminating Company NPCC 1

20 Saksena Saurabh National Grid NPCC 1

21 Schiavone Michael National Grid NPCC 1

Comments--NERC Compliance Application Notice mdash DRAFT

(for CAN-0017)

NPCC comments on Compliance Application Notice - Draft

middot On the posted Compliance Application Notice ndash Draft there is no identification of it as CAN-0017

middot The way the information in the CAN is organized is confusing A discussion of R5 R51 and R52 appears on p 2 and again on p 4 The discussion for R53 is similarly broken up

middot The CAN does not clarify the content of R53 regarding passwords

middot NPCCrsquos participating members that review and track the CANs through the process remain concerned that sufficient industry review is not undertaken due to the location of the posted materials on the NERC website and difficulty in accessing those materials

middot Concern exists with the process in general that it is not FERC nor industry approved does not reside in the ROPs and also does not result in an attachment to the standard nor are there any requirements for refiling with the FERC and Provincial authorities as does a formal interpretation to keep record of the matter

middot Comments received from industry are not made known through posting

middot The way the CAN is written is overly prescriptive and does not allow acceptable deviations from what is written in the Standard and by so doing are encouraging possible reductions in cyber security The ERO is moving to results based standards and specific objectives should be the only critical concern not how the objective is achieved The CAN should provide clarity on situations where the Entity exceeds the Requirementobjective via other means such as two factor authentication or one time passwords The CAN should not be necessitating the need for more TFEs in these situations The Entityrsquos other choice is to be strictly compliant by reducing cyber-security by implementing the minimal expectations as specified in the Standard This result is not desirable

middot On page 2 under Background ndash Password Controls states

ldquoConsequently registered entities under currently owned equipment software and security password schemes may not have the ability to ensure compliance with the standard via a fully compliant technical solution or the registered entity may not find it operationally feasible to comply under a technical solutionrdquo

middot The question of having a procedural control accepted when a technical solution is not available remains unanswered

middot On pages 2 and 3 under Compliance Application ndash System Access Controls states

ldquoNERC and the Regional Entities have determined that the ldquoandrdquo in R5 reflects that both technical and procedural controls are required throughout the sub-requirements R51 and R52 but both are not required for each of the actions required by R51 and R52 Therefore a registered entity must have implemented the appropriate control ndash either a technical or procedural control ndash as required for each actionrdquo

middot The issue of the acceptability of a procedural control needs to be addressed The above is contradictory and adds confusion Resolution of the procedural control ambiguity would resolve the contradiction and should be done during the next revision of the Cyber Standards as this will potentially result in a change to the Requirement

middot On page 3 under Compliance Application ndash Password Controls ndash 1 states

ldquoIf the softwarersquos technical solution only partially meets the requirements of the standard but the equipment has the capability to fulfill all requirements of the standard by also implementing a procedural solution for the remaining requirements the registered entity to be compliant with the standard should implement a procedural solution for any requirements that the technical solution cannot fulfill3rdquo

middot NPCC participating members do not agree with ldquofootnote 3rdquo which states the use of a procedural control when technical controls cannot enforce a requirement requires a TFE

middot Enforcement via procedural controls should be acceptable


ldquoIf a registered entity has equipment for which a partially or fully compliant technical solution is available4rdquo

middot ldquoFootnote 4rdquo introduces the term ldquoreasonablerdquo Reasonable is not a term that is objectively auditable and has in the past been rejected by FERC


ldquoAlthough the standard does not outline what constitutes a good procedural solution a sufficient procedural solution would include a compliant policy statement personnel training and other compensating measures such as requiring longer passwords restricting electronic access and a more frequent password change cycle6rdquo

middot The Standard does not state what constitutes a good procedural solution Acceptability should be determined through the approval of a TFE not by promulgating a CAN

middot On page 3 under Compliance Application ndash Password Controls ndash R53 - 3 states

ldquohellipneither a technical solution nor a procedural solution can be implementedrdquo

middot NPCC participating members suggest that this is the only situation that requires a TFE Equipment that cannot meet the Requirement is different from equipment not technically enforcing the Requirement

middot On page 4 under Compliance Guidance ndash Password Controls ndash 1 ndash b states

ldquoWhere a registered entityrsquos technical solution does not have the ability to fully meet the requirements of R53 the registered entity must have an approved TFE8helliprdquo

middot This appears to contradict the previous section which indicated that a TFE was necessary if a technical solution did not enforce the Requirement and there was no procedural solution

middot This contradicts Compliance application Password Controls - R53-3 on p 3 of the CAN that states ldquoIf a registered entity has equipment for which neither a technical solution nor a procedural solution can be implemented a registered entity in order to be compliant with the standard must obtain an approved TFE7rdquo This section is saying that a TFE is needed if only a technical solution is lacking

middot On page 4 under Compliance Guidance ndash Password Controls ndash 1 ndash b ndash v states

ldquoattestations from persons responsible for implementing andor complying with the procedural solutionrdquo

middot This is burdensome and unnecessary in the view of NPCCrsquos participating members It adds a level of measure to the Standard that does not currently exist

Page 3 of 4 322011

22 Sipperly Wayne New York Power Authority NPCC 5

23 Weaver Donald New Brunswick System Operator NPCC 2

24 Wu Ben Orange and Rockland Utilities NPCC 1

25 Yost Peter Consolidated Edison Co of New York Inc NPCC 3

Comments--NERC Compliance Application Notice mdash DRAFT(for CAN-0017)

NPCC comments on Compliance Application Notice - Draft middot On the posted Compliance Application Notice ndash Draft there is no identification of it as

CAN-0017middot The way the information in the CAN is organized is confusing A discussion of R5 R51

and R52 appears on p 2 and again on p 4 The discussion for R53 is similarly brokenup

middot The CAN does not clarify the content of R53 regarding passwordsmiddot NPCCrsquos participating members that review and track the CANs through the process

remain concerned that sufficient industry review is not undertaken due to the locationof the posted materials on the NERC website and difficulty in accessing those materials

middot Concern exists with the process in general that it is not FERC nor industry approveddoes not reside in the ROPs and also does not result in an attachment to the standardnor are there any requirements for refiling with the FERC and Provincial authorities asdoes a formal interpretation to keep record of the matter

middot Comments received from industry are not made known through postingmiddot The way the CAN is written is overly prescriptive and does not allow acceptable

deviations from what is written in the Standard and by so doing are encouragingpossible reductions in cyber security The ERO is moving to results based standards andspecific objectives should be the only critical concern not how the objective isachieved The CAN should provide clarity on situations where the Entity exceeds theRequirementobjective via other means such as two factor authentication or one timepasswords The CAN should not be necessitating the need for more TFEs in thesesituations The Entityrsquos other choice is to be strictly compliant by reducing cyber-security by implementing the minimal expectations as specified in the Standard Thisresult is not desirable

middot On page 2 under Background ndash Password Controls statesldquoConsequently registered entities under currently owned equipment software

and security password schemes may not have the ability to ensure compliancewith the standard via a fully compliant technical solution or the registered entitymay not find it operationally feasible to comply under a technical solutionrdquo

middot The question of having a procedural control accepted when a technical solution is

not available remains unanswered


ldquoNERC and the Regional Entities have determined that the ldquoandrdquo in R5 reflects thatboth technical and procedural controls are required throughout the sub-requirements R51 and R52 but both are not required for each of the actionsrequired by R51 and R52 Therefore a registered entity must have implementedthe appropriate control ndash either a technical or procedural control ndash as required foreach actionrdquo

middot The issue of the acceptability of a procedural control needs to be addressed Theabove is contradictory and adds confusion Resolution of the procedural controlambiguity would resolve the contradiction and should be done during the nextrevision of the Cyber Standards as this will potentially result in a change to theRequirement


ldquoIf the softwarersquos technical solution only partially meets the requirements of thestandard but the equipment has the capability to fulfill all requirements of thestandard by also implementing a procedural solution for the remainingrequirements the registered entity to be compliant with the standard shouldimplement a procedural solution for any requirements that the technical solution

cannot fulfill3rdquo

middot NPCC participating members do not agree with ldquofootnote 3rdquo which states the useof a procedural control when technical controls cannot enforce a requirementrequires a TFE

middot Enforcement via procedural controls should be acceptable middot On page 3 under Compliance Application ndash Password Controls ndash 2 states

ldquoIf a registered entity has equipment for which a partially or fully compliant

technical solution is available4rdquo

middot ldquoFootnote 4rdquo introduces the term ldquoreasonablerdquo Reasonable is not aterm that is objectively auditable and has in the past been rejected byFERC


ldquoAlthough the standard does not outline what constitutes a good proceduralsolution a sufficient procedural solution would include a compliant policystatement personnel training and other compensating measures such as requiringlonger passwords restricting electronic access and a more frequent password

change cycle6rdquo

middot The Standard does not state what constitutes a good procedural solution Acceptability should be determined through the approval of a TFE not bypromulgating a CAN



middot NPCC participating members suggest that this is the only situation that requires aTFE Equipment that cannot meet the Requirement is different from equipmentnot technically enforcing the Requirement


ldquoWhere a registered entityrsquos technical solution does not have the ability to fullymeet the requirements of R53 the registered entity must have an approved

TFE8helliprdquo

middot This appears to contradict the previous section which indicated that a

TFE was necessary if a technical solution did not enforce theRequirement and there was no procedural solution

middot This contradicts Compliance application Password Controls - R53-3on p 3 of the CAN that states ldquoIf a registered entity has equipment forwhich neither a technical solution nor a procedural solution can beimplemented a registered entity in order to be compliant with thestandard must obtain an approved TFE7rdquo This section is saying thata TFE is needed if only a technical solution is lacking


ldquoattestations from persons responsible for implementing andor complying withthe procedural solutionrdquo


Lee PedowiczManager Reliability StandardsNPCC212-840-1070

From Lee R PedowiczTo cancommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject FW Draft CAN-0018 FAC-008 R121 Terminal EquipmentDate Friday February 18 2011 51844 PM

Following are NPCCrsquos comments on CAN-0018 middot A CAN is for guidance and should not be prescriptive as this ismiddot The Draft CAN-0018 states that terminal equipment is ldquoAny piece of equipment that is in series

with the circuit and that could become a limiting elementrdquo Equipment such as potentialdevices shunt capacitors shunt reactors for example do not meet this criteria as they are notconnected in series with a facility and cannot become a thermally limiting element




Senior Vice President amp General Counsel DATE March 9 2011 SUBJECT Summary of Comments on Proposed Changes to Section 1700 of the NERC Rules of

Procedure ndash Challenges to Determinations On January 21 2011 NERC posted a proposed addition to the NERC Rules of Procedure for Section 1700 ndash Challenges to Determinations which pertains to the development of an appeals process for challenging criticality determinations made by Planning Coordinators under PRC-023-1 ndash Transmission Relay Loadability This proposed change is in compliance with Paragraph 97 of Order No 733 which states

97 Finally commenters argue that there should be some mechanism for entities to challenge criticality determinations We agree that such a mechanism is appropriate and direct the ERO to develop an appeals process (or point to a process in its existing procedures) and submit it to the Commission no later than one year after the date of this Final Rule

NERC posted the proposed Section 1700 for a public comment period ending on March 7 2011 Nine parties provided comments in response to the proposed changes Proposed Section 1700 was widely supported by all those who commented Comments were received from American Electric Power Duke Energy FirstEnergy ISO New EnglandPJM Kansas City Power amp Light NextEra Energy Inc Northeast Power Coordinating Council National Rural Electric Cooperative Association and Southern Company A summary of their comments is included below The full comments are posted at the following location httpwwwnerccompagephpcid=1|8|169 Comments received were generally focused on the following points

bull Several commenters requested more clarity regarding the intent of Section 1700 One commenter specifically pointed out that the scope of authority in Section 1701 was vague and NERC should state that Section 1701 governs appeals under the PRC-023 Reliability Standard Other commenters requested that Section 1700 not be limited to situations presented solely by the PRC-023 Reliability Standard

bull One commenter proposed revising Section 17021 to more closely match the language in FERCrsquos

Order No 733 directive for facilities that ldquoare critical to the reliability of the bulk power systemrdquo rather than the proposed Section 17021 language which provides for ldquocircuits in [the] Planning Coordinator Area for which Registered Entities must comply with the standardrdquo

bull Several commenters suggested modifying the proposed Section 1700 to more clearly define and

formalize the timeframes for every step of the appeal process for expediency and monitoring purposes One commenter suggested that the opportunity to appeal not be left open-ended and

-2-

proposed that a 60-day window from the date of notification to file an appeal Another commenter suggested setting the deadlines for submitting requests to the NERC Board of Trustees and to applicable governmental authorities to 30 days each Another commenter requested a definite time period by which the Board of Trustees must (i) decline to review the decision of the panel and (ii) issue a determination (if it wishes to do so) on appeal

bull Two commenters suggested that the proposed rule should include a statement of the standard of review that should be applied in making decisions on challenges

bull One commenter requested that a list of criteria similar to that included in Section 17026

regarding the make-up of the appeal panel at the NERC Board of Trustee level be added to paragraph 17024 regarding the make-up of the appeal panel at the Regional Entity level

bull Several commenters requested clarification on the compliance expectations during the challenge

process and suggestions were made to suspend compliance obligations while the appeals process is ongoing

bull One commenter suggested limiting the authority granted in Section 17025 to appeal decisions to

only affected Registered Entities rather than ldquoany entityrdquo bull Two commenters proposed adding additional procedures to require Planning Coordinators to

establish their own formal processes for receiving challenges to determinations One commenter suggested that these provisions would also clarify which Planning Coordinator personnel should be provided with the notice of a challenge from a Registered Entity

In response to comments received NERC made the following changes to the proposed Section 1700

bull Section 17021 was modified to more closely track the language in the PRC-023 standard to specify that a challenge of a Planning Coordinatorrsquos determination will apply to sub-200kV circuits in its Planning Coordinator area for which Transmission Owners Generator Owners and Distribution Providers must comply with PRC-023

bull Section 17022 was added to include more clarity on procedures the Planning Coordinator must follow This includes establishing a procedure for a Registered Entity to submit a written request for an explanation of a determination made by the Planning Coordinator timelines for submitting such a request and a timeline for responding to such a request

bull Section 17023 was modified to provide more clarity on the elements required to support a Registered Entityrsquos challenge of a Planning Coordinatorrsquos determination

bull Section 17024 was added to state that a challenge filed in good faith would suspend the time

period for compliance with the PRC-023 standard for the particular facility involved until the challenge is withdrawn settled or resolved

bull Section 17025 was modified to provide more clarity regarding what is required in the Regional

Entityrsquos decision on the challenge by a Registered Entity Section 17025 also includes the standard of review The Regional Entity should affirm the determination of the Planning Coordinator if it is supported by substantial evidence

bull Section 17026 was modified to state that a Regional Entities Registered Entity or Planning

Coordinator may file a response to an appeal within 30 days of the appeal

-3-

bull Section 17027 was modified to provide more clarity to the scope of the panel that the Board of

Trustees appoints to hear appeals from Regional Entity decisions regarding PRC-023 A time period of 90 days for the panel to issue its decision was also added to this section

bull Section 17028 was modified to clarify the process that the Board of Trustees will use in

reviewing decisions issued by the panel appointed by the board Importantly review by the Board of Trustees is at the Boardrsquos discretion The process includes three options (a) issuing a decision on the merits which shall be the final NERC decision (b) issuing a notice declining to review the decision of the panel in which case the panelrsquos decision shall be the final NERC decision or (3) if no written decision or notice declining review is issued within 90 days the appeal shall have been deemed denied by the board

bull Section 17029 was modified to provide that a Registered Entity or Planning Coordinator may

appeal the final NERC decision to the applicable governmental authority within 30 days of the decision

bull Section 170210 was modified to encourage the Planning Coordinators and Registered Entity to

resolve any disputes using alternative dispute resolution procedures One commenter suggested that a Regional Entity should be required to make use of the formal hearing procedures from the Compliance Monitoring and Enforcement Program for deciding all challenges under PRC-023 We did not implement that change because we do not believe the nature of the decision warrants those formal procedures A redline of the changes to Section 1700 from those included in the Board of Trusteesrsquo agenda package dated March 7 2011 is included with this memo for your reference

1

PROPOSED NEW SECTION FOR NERC RULES OF PROCEDURE [DRAFT March 8 2011] SECTION 1700 mdash CHALLENGES TO DETERMINATIONS 1701 Scope of Authority

Whenever a Reliability Standard or term defined in the Glossary of Terms Used in NERC Reliability Standards provides a Registered Entity with the opportunity to challenge a determination made pursuant to the Reliability Standard or Defined Term this Section 1700 shall sets forth the process procedures to be followed for Registered Entities to challenge determinations made under various Reliability Standards or terms defined in the Glossary of Terms Used in NERC Reliability Standards

1702 Challenges to Determinations by Planning Coordinators Under Reliability

Standard PRC-023

1 This Rule Section 1702 establishes the procedures to be followed when a Registered Entity wishes to challenge a determination by a Planning Coordinator of the sub-200 kV circuits in its Planning Coordinator area that are critical to the reliability of the bulk electric system and for which Transmission Owners Generator Owners and Distribution Providers (defined as ldquoRegistered Entitiesrdquo for purposes of this Section 1702) must comply with ollowing the Planning Coordinatorrsquos application of the test adopted in Attachment B of the requirements of Reliability Standard PRC-023 to determine the circuits in its Planning Coordinator area for which Registered Entities must comply with the standard

2 Planning Coordinator Procedures

21 Each Planning Coordinator shall establish a procedure for a Registered Entity to submit a written request for an explanation of a determination made by the Planning Coordinator under PRC-023

22 A Registered Entity shall follow the procedure established by the

Planning Coordinator for submitting the request for explanation and submit any such request not later than 60 days after receiving the determination under PRC-023 from the Planning Coordinator

23 Not later than 30 days after receiving a written request from a

Registered Entity under Section 17022 the Planning Coordinator shall provide the Registered Entity with a written explanation of the basis for its determination under PRC-023 unless the Planning Coordinator provided a written explanation of the basis for its

2

determination when it initially informed the Registered Entity of its determination

1 Within 30 days of receiving a written request from a Registered Entity a

Planning Coordinator shall provide the Registered Entity with a written explanation of the basis for its determination under Attachment B of PRC-023 Planning Coordinators and Registered Entities are encouraged to meet informally to resolve any differences

3 A Registered Entity may challenge the determination of the Planning

Coordinator by filing with the appropriate Regional Entity with a copy to and the Planning Coordinator within not later than 60 days of after receiving the written explanation from the Planning Coordinator The challenge shall include the following (a) an explanation of the technical reasons for its disagreement with the Planning Coordinatorrsquos determination along with any supporting documentation and (b) a copy of the Planning Coordinatorrsquos written explanation its objection the written explanation from the Planning Coordinator and the Registered Entityrsquos supporting documents and reasons The challenge may only raise issues that were first presented to and discussed with the Planning Coordinator Not later than 30 days after receipt of a challenge the Planning Coordinator may file a response with the Regional Entity with a copy to the Registered Entity

24 The filing of a challenge in good faith shall suspend the time period for

compliance with PRC-023 with respect to the subject facility until such time as the challenge is withdrawn settled or resolved

35 The Regional Entity shall issue its written decision setting forth the basis

of its determination within not later than 90 days after it receives the filingchallenge and send copies of the decision to the Registered Entity and the Planning Coordinator The Regional Entity may convene a meeting of the involved entities and may request additional information The Regional Entity shall affirm the determination of the Planning Coordinator if it is supported by substantial evidence

46 Any A Planning Coordinator or entity aggrievedRegistered Entity affected

by the decision of the Regional Entity may within not later than 30 days of after the decision file an appeal with NERCrsquos Chief Reliability Officer with copies to the Regional Entity and the Planning Coordinator or Registered Entity The appeal shall state the basis of the objection to the decision of the Regional Entity and shall include the Regional Entity decision the written explanation of the Planning Coordinatorrsquos determination under PRC-023 and the documents and reasoning filed by the Registered Entity with the Regional Entity in support of its objection The Regional Entity Planning Coordinator

3

or Registered Entity may file a response to the appeal within 30 days of the appeal

57 A panel appointed by the The NERC Board of Trustees shall appoint a panel to decide appeals from Region Entity decisions under Section 17025 for that purpose shall decide the appeal within 90 days The panel which may contain alternates shall consist of at least three appointees one of whom must be a member of the NERC staff who are knowledgeable about PRC-023 and transmission planning and do not have a direct financial or business interest in the outcome of the appeal The panel may request additional information from the parties The panel shall decide the appeal within 90 days of receiving the appeal from the decision of the Regional Entity and shall affirm the determination of the Planning Coordinator if it is supported by substantial evidence

8 Any party aggrievedThe Planning Coordinator or Registered Entity affected

by the decision of the panel may request that the NERC Board of Trustees review the decision by filing its request for review and a statement of reasons with NERCrsquos Chief Reliability Officer within not later than 14 30 days of after the panel decision The Board of Trustees may in its discretion decline to review the decision of the panel in which case the decision of the panel shall be the final NERC decision Not later than 90 days after the request for review under this Section 17028 the NERC Board of Trustees may either (a) issue a decision on the merits which shall be the final NERC decision or (b) issue a notice declining to review the decision of the panel in which case the decision of the panel shall be the final NERC decision If no written decision or notice declining review is issued within 90 calendar days the appeal shall be deemed to have been denied by the NERC Board of Trustees and this will have the same effect as a notice declining review

69 The Registered Entity or Planning Coordinator may appeal the final

NERC decision to the applicable governmental authority not later than 30 days after receipt of the Board of Trusteesrsquo final decision or notice declining review or expiration of the 90-day review period without any action by NERC subject only to an appeal to the applicable governmental authority filed within 21 days of the Boardrsquos determination

710 The Planning Coordinator and Registered Entity are encouraged but not

required to meet to resolve any dispute including the use of mutually agreed-upon alternative dispute resolution procedures at any time during the course of the matter Interested parties are encouraged to resolve any disagreements informally and the involved parties may make use of alternative dispute resolution procedures at any time during the course of the matterIn the event the parties reach a resolution after the filing of a challenge the Registered Entity and Planning Coordinator shall jointly provide to the applicable Regional Entity and if applicable NERC and the

4

applicable governmental authority a written acknowledgement of withdrawal of the challenge or appeal including a statement that all outstanding issues have been resolved

From Elizabeth HeenanTo rebeccabaldwinspiegelmcdcom LauraLeeduke-energycom MikeGammonkcplcom

jtwoodsoutherncocom hohlbaughdgfirstenergycorpcom mgoldbergiso-necombarrylawsonnrecacoop Lee R Pedowicz brianjmurphyfplcom tefoltzaepcom

Cc davidcooknercnet Sara MingesSubject NERC memo on Section 1700 Following Comment PeriodDate Wednesday March 09 2011 30451 PMAttachments Memo to Board on Section 1700 ROP changes FINALrpdf

Good Afternoon Attached please find a memo from David Cook to the NERC Board of Trustees regarding theproposed Section 1700 to the NERC Rules of Procedure NERC appreciates the comments providedand made a number of changes to accommodate the commenters The memo includes discussionof those comments and proposed changes to section 1700 Thank you

Elizabeth A HeenanLegal AssistantNorth American Electric Reliability Corporation1120 G Street NWSuite 990Washington DC 20005Phone (202) 393-3998Direct (202) 383-2634Fax (202) 393-3955elizabethheenannercnet












-2-




















-3-









1




Standard PRC-023








2












3









4


From Lee R PedowiczTo rdacommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to DeterminationsDate Monday March 07 2011 125841 PM

Good afternoon Good afternoon Below are NPCCrsquos Comments to NERCrsquos Proposed Changes to its Rules of Procedure for Compliancefiling in Response to Order 733 - Section 1700 Challenges to Determinations

NERCrsquos Proposed Changes to its Rules ofProcedure for Compliance Filing in Response toOrder No 733 Section 1700- Challenges to Determinations PROPOSED NEW SECTION FOR NERC RULES OF PROCEDURE[DRAFT January 18 2011] SECTION 1700 mdash CHALLENGES TO DETERMINATIONS 1701 Scope of AuthorityWhenever a Reliability Standard or term defined in the Glossary of Terms Used in NERCReliability Standards provides a Registered Entity with the opportunity to challenge adetermination made pursuant to the Reliability Standard or Defined Term this Section 1700 shallset forth the process to be followed Propose deleting This section does not need a general reference to the ldquoGlossary of TermsrdquoA statement about ldquoScope of Authorityrdquo in Section 1700 should be limited to addressingRegistered Entities challenges to determinations made by Planning Coordinators as may beapplicable under PRC-023 only Suggest using 17021 for 1701 1702 Challenges to Determinations by Planning Coordinators Under Reliability StandardPRC-023 1 This Rule 1702 establishes the procedures to be followed when a Registered Entity wishes tochallenge a determination by a Planning Coordinator following the Planning Coordinatorrsquosapplication of the test adopted in Attachment B of PRC-023 to determine the circuits in itsPlanning Coordinator area for which Registered Entities must comply with the standard

Suggest moving this section (17021) to 1701 to establish the ldquoScope of Authorityrdquo andreplace with the following 1 Establishment of processes to challenge Planning Coordinator determinations a A Planning Coordinator shall establish the process for Registered Entities to submit aformal written challenge a determination made by the Planning Coordinator per PRC-023 b A Registered Entity shall follow the process established by the Planning Coordinator toregister formally its request to challenge the determination per these Rules of Procedure This type of provision is needed so that there is no confusion about whether or not theRegistered Entity has provided proper notice to the Planning Coordinator of its intent tochallenge the determination Without following established procedures there may bequestions about whether the notice of the challenge was properly presented to the rightpersonnel at the Planning Coordinator 2 Within 30 days of receiving a written request from a Registered Entity in accordance with17021 a Planning Coordinator shall provide the Registered Entity with a written explanation ofthe basis for its determination under Attachment B of PRC-023 unless the Planning Coordinatorprovided the basis of its determination when it originally informed the Registered Entity of itsdetermination Planning Coordinators and Registered Entities are encouraged to meet informally toresolve any differences This language is not enforceable and does not describe a ldquoprocessrdquo step It should not beincluded in the Rules of Procedure 3 A Registered Entity may challenge the determination of the Planning Coordinator by filing withthe appropriate Regional Entity and the Planning Coordinator within 60 days of receiving thewritten explanation its objection the written explanation from the Planning Coordinator and theRegistered Entityrsquos supporting documents and reasons The challenge may only raise issues thatwere first presented to and discussed with the Planning Coordinator 4 The Regional Entity shall issue its decision within 90 days after it receives the filing TheRegional Entity may convene a meeting of the involved entities and may request additionalinformation 5 Any entity aggrieved by the decision of the Regional Entity may within 30 days of the decisionfile an appeal with NERC with copies to the Regional Entity and the Planning Coordinator orRegistered Entity The appeal shall state the basis of the objection to the decision of the RegionalEntity and shall include the Regional Entity decision the written explanation of the Planning Coordinator and the documents and reasoning filed by the Registered Entity with the RegionalEntity in support of its objection 6 A panel appointed by the NERC Board of Trustees for that purpose shall decide the appealwithin 90 days The panel shall consist of at least three appointees one of whom must be amember of the NERC staff who are knowledgeable about PRC-023 and transmission planning anddo not have a direct financial or business interest in the outcome of the appeal The panel mayrequest additional information from the parties

Regarding the preceding highlighted section better language is needed to establishqualification Perhaps make reference to degrees needed Is this language needed Isnrsquot thisassured by virtue of the fact that the personnel are coming from NERC 7 Any party aggrieved by the decision of the panel may request that the NERC Board of Trusteesreview the decision by filing its request for review and a statement of reasons with NERCrsquos ChiefReliability Officer within 14 days of the panel decision The Board of Trustees may in itsdiscretion decline to review the decision of the panel in which case the decision of the panel shallbe the final NERC decision subject only to an appeal to the applicable governmental authorityfiled within 21 days of the Boardrsquos determination 8 Interested parties are encouraged to resolve any disagreements informally and the involvedparties may make use of alternative dispute resolution procedures at any time during the course ofthe matter

From Elizabeth HeenanTo Lee R Pedowicz rdacomments Sara MingesCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject RE Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to DeterminationsDate Monday March 07 2011 15111 PM

Lee Pedowicz I have received and posted the comments you submitted on behalf of NPCC All comments areposted on the Rules of Procedure webpage under the January 21 postinghttpwwwnerccompagephpcid=1|8|169 Thank you


From Lee R Pedowicz [mailtolpedowicznpccorg] Sent Monday March 07 2011 1258 PMTo rdacommentsCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to Determinations Good afternoon Good afternoon Below are NPCCrsquos Comments to NERCrsquos Proposed Changes to its Rules of Procedure for Compliancefiling in Response to Order 733 - Section 1700 Challenges to Determinations

NERCrsquos Proposed Changes to its Rules ofProcedure for Compliance Filing in Response toOrder No 733 Section 1700- Challenges to Determinations

PROPOSED NEW SECTION FOR NERC RULES OF PROCEDURE[DRAFT January 18 2011] SECTION 1700 mdash CHALLENGES TO DETERMINATIONS 1701 Scope of AuthorityWhenever a Reliability Standard or term defined in the Glossary of Terms Used in NERCReliability Standards provides a Registered Entity with the opportunity to challenge adetermination made pursuant to the Reliability Standard or Defined Term this Section 1700 shallset forth the process to be followed Propose deleting This section does not need a general reference to the ldquoGlossary of TermsrdquoA statement about ldquoScope of Authorityrdquo in Section 1700 should be limited to addressingRegistered Entities challenges to determinations made by Planning Coordinators as may beapplicable under PRC-023 only Suggest using 17021 for 1701 1702 Challenges to Determinations by Planning Coordinators Under Reliability StandardPRC-023 1 This Rule 1702 establishes the procedures to be followed when a Registered Entity wishes tochallenge a determination by a Planning Coordinator following the Planning Coordinatorrsquosapplication of the test adopted in Attachment B of PRC-023 to determine the circuits in itsPlanning Coordinator area for which Registered Entities must comply with the standard Suggest moving this section (17021) to 1701 to establish the ldquoScope of Authorityrdquo andreplace with the following 1 Establishment of processes to challenge Planning Coordinator determinations a A Planning Coordinator shall establish the process for Registered Entities to submit aformal written challenge a determination made by the Planning Coordinator per PRC-023 b A Registered Entity shall follow the process established by the Planning Coordinator toregister formally its request to challenge the determination per these Rules of Procedure This type of provision is needed so that there is no confusion about whether or not theRegistered Entity has provided proper notice to the Planning Coordinator of its intent tochallenge the determination Without following established procedures there may bequestions about whether the notice of the challenge was properly presented to the rightpersonnel at the Planning Coordinator 2 Within 30 days of receiving a written request from a Registered Entity in accordance with17021 a Planning Coordinator shall provide the Registered Entity with a written explanation ofthe basis for its determination under Attachment B of PRC-023 unless the Planning Coordinatorprovided the basis of its determination when it originally informed the Registered Entity of itsdetermination Planning Coordinators and Registered Entities are encouraged to meet informally toresolve any differences This language is not enforceable and does not describe a ldquoprocessrdquo step It should not be

included in the Rules of Procedure 3 A Registered Entity may challenge the determination of the Planning Coordinator by filing withthe appropriate Regional Entity and the Planning Coordinator within 60 days of receiving thewritten explanation its objection the written explanation from the Planning Coordinator and theRegistered Entityrsquos supporting documents and reasons The challenge may only raise issues thatwere first presented to and discussed with the Planning Coordinator 4 The Regional Entity shall issue its decision within 90 days after it receives the filing TheRegional Entity may convene a meeting of the involved entities and may request additionalinformation 5 Any entity aggrieved by the decision of the Regional Entity may within 30 days of the decisionfile an appeal with NERC with copies to the Regional Entity and the Planning Coordinator orRegistered Entity The appeal shall state the basis of the objection to the decision of the RegionalEntity and shall include the Regional Entity decision the written explanation of the Planning Coordinator and the documents and reasoning filed by the Registered Entity with the RegionalEntity in support of its objection 6 A panel appointed by the NERC Board of Trustees for that purpose shall decide the appealwithin 90 days The panel shall consist of at least three appointees one of whom must be amember of the NERC staff who are knowledgeable about PRC-023 and transmission planning anddo not have a direct financial or business interest in the outcome of the appeal The panel mayrequest additional information from the parties Regarding the preceding highlighted section better language is needed to establishqualification Perhaps make reference to degrees needed Is this language needed Isnrsquot thisassured by virtue of the fact that the personnel are coming from NERC 7 Any party aggrieved by the decision of the panel may request that the NERC Board of Trusteesreview the decision by filing its request for review and a statement of reasons with NERCrsquos ChiefReliability Officer within 14 days of the panel decision The Board of Trustees may in itsdiscretion decline to review the decision of the panel in which case the decision of the panel shallbe the final NERC decision subject only to an appeal to the applicable governmental authorityfiled within 21 days of the Boardrsquos determination 8 Interested parties are encouraged to resolve any disagreements informally and the involvedparties may make use of alternative dispute resolution procedures at any time during the course ofthe matter This email and any of its attachments may contain information that is privilegedconfidential classified as CEII or subject to copyright belonging to NPCC This email isintended solely for the use of the individual or entity to which it is addressed If you are notthe intended recipient of this email you are hereby notified that any disseminationdistribution copying or action taken in relation to the contents of and attachments to thisemail is strictly prohibited and may be unlawful If you receive this email in error pleasenotify the sender immediately and permanently delete the original and any copy of this email

and any printout

Agenda 3-16-11

NPCC Regional Standards Committee

Preliminary Agenda--Draft

Meeting 11-2


ReliabilityFirst Corporation - Reliability Standards Voting Process

MOD-025-RFC-01 - Verification and Data Reporting of Generator Gross and Net Reactive Power Capability passed its 15 day Category vote and was approved by the RFC Board of Directors at their March 3 2011 Meeting

Midwest Reliability Organization - Reliability Standards Voting Process

l NERC Operating Committee March 8-9 2011 Meeting--notes

m NERC Planning Committee March 8-9 2011 Meeting--notes


2011 RSC Conference Call Schedule

(call 212-840-1070--ask for the RSC [Guyrsquos or Leersquos] Conference Call)

Guy V Zito Chair RSC

Action Item List

Action_Item_68--NPCC Regional Reliability Standards Development Procedure BG_KC_v1 0

Steps 1 and 2 Request to Develop a New Regional Standard

Steps 3 4 and 5 RSC Accepts RSAR and RCC Assigns TF to Draft New or Revised Standard

Step 6 Solicit Public Comments on Draft Regional Standard

Steps 7 8 and 9 Open Process Posting and Analysis of the Comments

Steps 10 and 11 RSC Approves of the New or Revised Standard For Posting

Appendix A








Related Standards

-t


Action_Item_69--RSC Scope Revision for BOD ApprovalRev5Draft 2 24 11 redline

Item_1a--Draft for Comment 2-8-11 BOD Minutes

Item_2--Minutes--RSC_2-2-11_Meeting--Draft--3-1-11


Draft Minutes for Approval

Meeting 11-1



MOD-025-RFC-01 - Verification and Data Reporting of Generator Gross and Net Reactive Power Capability passed its 15 day Category vote Anticipated RFC Board of Directors action to approve to approve during their March 3 2011 m


The RSC November Meeting dates have to be changed because of a conflict with the NPCC Annual and General Meetings

Meeting adjourned 1221 Feb 3 2011





Action Item List

Item_4a--Standards Development Executive Tracking Summary 3 10 11

NERC RS Exec Tracking Summary

NPCC RRS Tracking Summary

NPCC Doc Tracking Summary

NPCC Directory Tracking Summary

Item_5a--FERC_2-17-11_Meeting_Agenda

Item_5b--March 17 FERC Open Meeting Agenda

Item_5b--March 17 2011 FERC Open Meeting Agenda

Item_5-T1--FW_ NERCs Draft Response to FERCs Notice of Proposed Rulemaking (NOPR)_ The Integration of Variable Energy Resources

Item_5-T1--NERC_draft_VER_NOPR_comments_02-25-11

Item_5-T2--20110228-5264(25060793)

Final_NUC_filing_DraftQ42010_20110228(PUBLIC)PDF

Document Content(s)

Item_5-T2--GZ_E-mail--Answer_Response to a Pleading_Motion submitted in FERC RM06-16-000 by North American Electric Reliability Corporationet al

Item_5-U1--FW_ Commission Order_Opinion issued in FERC RM06-22-014

Item_5-U1--Mandatory_Reliability_Standards_for_CIP_March_18_2010

I Background

II NERC Compliance Filing

III Notice and Responsive Pleadings

IV Commission Determination

Item_9a--2009-02_RTTSDT_Third_Posting_SAR_Redline_Last_Posting_2010April1

Standard Authorization Request Form



Related Standards

Related SARs

Regional Variances

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

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


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

Applicable Reliability Principles (Check box for all that apply)

Explanation

Standard No

Explanation

SAR ID

Explanation

Region

Item_9a--Project_2009-02_rmacsdt_white_paper_021611

10 INTRODUCTION

20 MONITORING

21 PERFORMANCE

211 Status Data

212 Analog Data

213 Data Display

22 AVAILABILITY

23 FAILURE NOTIFICATION

24 MAINTENANCE

30 DATA EXCHANGE

31 PERFORMANCE

32 AVAILABILITY


34 MAINTENANCE

40 ALARMING

41 PERFORMANCE

42 AVAILABILITY


44 MAINTENANCE

50 ANALYSIS

51 PERFORMANCE

511 Periodicity

512 Results Quality

52 AVAILIBILITY


54 MAINTENANCE

Item_9a--RE_ RSC Meeting--March 16-17 2011

Item_9a--Standards Announcement - Informal Comment Period Open - Project 2009-02 Real-time Monitoring and Analysis Capabilities

Item_9b--Comment Period Opens for Proposed Changes to ReliabilityFirst Corporation Rules of Procedure Pertaining to Regional Standards Development Process

Item_9b--Final_Posting_RFC_Standards_Process_Changes_20110301

Transmittal of Revised SDP to NERC - 2011014pdf

Att A - RFC_Reliability_Stds_Development_Procedure_V3_121510pdf

ReliabilityFirst CorporationReliability Standards Development Procedure

Version 3

ReliabilityFirst Corporation Reliability Standards Development ProcedureTable of Contents

ReliabilityFirst Corporation Reliability Standards Development Procedure

Introduction

Regional Reliability Standard Format Requirement Template Example

Maintenance of Regional Reliability Standards Development Process

Appendix B

Standard Authorization Request

SAR Originator Information

Name


Related Standards (NERC and Regional)

Related SARs

Implementation Plan

Assignments

Assignment

Team Members

ReliabilityFirst Staff

Appendix C

Appendix D

Ballot Pool Categories

For the purposes of category Ballot Pool registration and voting a person or entity may join the registered Ballot Pool to vote on standards whether or not such person or entity is a member of ReliabilityFirst

A corporation or other organization with integrated operations or with affiliates that qualifies to belong to more than one category (eg Transmission Owners and Load Serving Entities) may join and vote once in each category for which it qualifies provided that each category constitutes a separate membership in the Ballot Body and the organization is represented in each category by a different representative Affiliated entities are collectively limited to one membership in each category in the Ballot Pool for which they are qualified

Category 1 ndash Transmission Owner Transmission Operator Transmission Service Provider

Item_9c--Final_Posting_Appendices_3B_3D_20110301 (3)

Final_Appendix_3B_Cleanpdf

Purpose

Responsibilities for This Procedure

Guiding Principles

Standards Committee Membership

Standards Committee Membership Term

Standards Committee Officers

Standards Committee Scope and Conduct of Business

Segment Representative Nominations

Segment Representative Elections

Election Formula

Representation from Canada

Special Elections

The Standards Committeersquos officers shall determine the need for a special election to fill a vacant Standards Committee position between regular elections considering among other things the timing of the last and the next regular election If a nee

Alternative Procedures


Purpose


Guiding Principles







Election Formula


Special Elections



Final_Appendix_3B_Redlinepdf

Purpose


Guiding Principles







Election Formula


Special Elections



Final_Appendix_3Dpdf

Appendix 3DB mdash Development of the Registered Ballot Body0F

Registration Procedures

Segment Qualification Guidelines

Segments

Segment 1 Transmission Owners

Segment 2 Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)

Segment 3 Load-Serving Entities (LSEs)

Segment 4 Transmission Dependent Utilities (TDUs)

Segment 5 Electric Generators

Segment 6 Electricity Brokers Aggregators and Marketers

Segment 7 Large Electricity End Users

Segment 8 Small Electricity Users

Segment 9 Federal State and Provincial Regulatory or other Government Entities

Segment 10 Regional Reliability Organizations and Regional Entities


Purpose


Guiding Principles







Election Formula


Special Elections




Purpose


Guiding Principles







Election Formula


Special Elections



Final_Appendix_3D(CLEAN)pdf

Appendix 3D mdash Development of the Registered Ballot Body0F



Segments










Segment 10 Regional Entities

Final_Appendix_3D(REDLINE)pdf




Segments











Item_9c--FW_ Comment Period Opens for Proposed Changes to NERC Rules of Procedure Appendices 3B and 3D

Item_9d--2010-07_Attachment 1_FAC-001-0

Version

Item_9d--2010-07_Attachment 2_FAC-003-2_Draft_5

Standard Development Timeline

Development Steps Completed

Proposed Action Plan and Description of Current Draft

Future Development Plan

Effective Dates

Version History

Definitions of Terms Used in Standard

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

Vegetation Inspection

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 preventin

4 Applicability

41 Functional Entities

Transmission Owners

42 Facilities Defined below (referred to as ldquoapplicable linesrdquo) including but not limited to those that cross lands owned by federal0F state provincial public private or tribal entities

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

Requirements and Measures

R1 Each Transmission Owner and Generator Owner shall manage 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 Intercon

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

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

R2 Each Transmission Owner and Generator Owner shall manage 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 withi


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



Compliance

Time Horizons Violation Risk Factors and Violation Severity Levels

Variances

Interpretations

None

Guideline and Technical Basis

Requirement R7

FAC-003 mdash Table 2 mdash Minimum Vegetation Clearance Distances (MVCD)4F

Item_9d--2010-07_White_Paper_Proposal_for_Informal_Comment

Introduction

Objective

Proposed Next Steps and Review of Reliability Standards

Summary and Discussion of Other Solutions

Item_9d--Project_2010-07_Standards_Announcement_030411

Item_9e--EOP-004-2_redline_to_last_posting_20110308





Effective Dates

1 USA The standard shall become effective on the Ffirst calendar day of the firstthird calendar quarter one year after the date of the order providing applicable regulatory authority approval for all requirements

2 Canada and Mexico First calendar day ofConcurrent with the first calendar quarter one year following Board of Trustees adoption unless governmental authority withholds approvalEffective Date for the USA In those jurisdictions where no regulatory

Version History


None

Impact Event Any event which has either impacted or has the potential to impact the reliability of the Bulk Electric System Such events may be caused by equipment failure or mis-operation environmental conditions or human action

Introduction

1 Title Impact Event and Disturbance Assessment Analysis and Reporting

2 Number EOP-004-2

3 Purpose Responsible Entities shall report impact events and their known causes to support situationalTo improve industry awareness and the reliability of the Bulk Electric System (BES)by requiring the reporting of Impact Events and their causes if k

4 Applicability

41 Functional Entities Within the context of EOP-004-2 the term ldquoResponsible Entityrdquo shall mean

411 Reliability Coordinator

412 Balancing Authority

413 Interchange Authority

414 Transmission Service Provider

415 Transmission Owner

416 Transmission Operator

417 Generator Owner

418 Generator Operator

419 Distribution Provider

411 Electric Reliability Organization


R3

R2 Each ApplicableResponsible Entity shall identify and assess initial probable cause of impact events listed in Attachment 1 in accordance with itsimplement its Impact Event Operating Plan documented in Requirement R2R1 for Impact Events listed i

Compliance

Variances

Interpretations

EOP-004 - Attachment 1 Impact Events Table

EOP-002004 - Attachment 2 Impact Event Reporting Form


Introduction

Summary of Concepts and Assumptions

Discussion of Disturbance Reporting

Discussion of ldquoimpact eventImpact Eventrdquo Reporting

Collection of Reportable Information or ldquoOne stop shoppingrdquo

Item_9e--Project_2009-01_CIP-001-1

Version History

Item_9e--Project_2009-01_EOP-004-1

Version History

Table 1-EOP-004-0

Summary of NERC and DOE Reporting Requirements for Major Electric System Emergencies

All entities required to file a DOE EIA-417 report (Schedule 1 amp 2) shall send a copy of these reports to NERC simultaneously but no later than 24 hours after the start of the incident or disturbance

Item_9e--Project_2009-01_Implementation_Plan_20110308

The standard shall become effective on the first calendar day of the third calendar quarter after the date of the order providing applicable regulatory approval In those jurisdictions where no regulatory approval is required the standard shall becom

Item_9e--Project_2009-01_Standards_Announcement_030911

Item_11a--FW_ Comment Form--Project 2010-11 - TPL Table 1 Order

Item_11a--Standards Announcement - Recirculation Ballot Window Open January 26-February 5 2011 - Project 2010-11 TPL Table 1 Order

Item_11a--Standards Announcement_ Recirculation Ballot Results _ Project 2010-11 TPL Table 1 Footnote B

Item_11b--FW_ Standards Announcement_ Project 2007-07 Transmission Vegetation Management - Successive Ballot Results

Item_11b--Project 2007-07 ― Vegetation Management ― FAC-003

Item_11b--Standards Announcement - Successive Ballot and Non-binding Poll Open _ Project 2007-07 Vegetation Management

Item_11c--FW_ Standards Announcement_ Project 2006-06 ndash Reliability Coordination _ Initial Ballot Results

Item_11c--NERC Ballot for Project 2006-06 Reliability Coordination COM-001 COM-002 IRO-001 and IRO-014

Item_11c--NERC Initial Ballot NPCC Recommendation-Project 2006-06 ― Reliability Coordination ― COM-001 COM-002 IRO-001 and IRO-014

Item_11c--Standards Announcement - Ballot Window Open February 25 - March 7 2011 _ Project 2006-06

Item_11d--FW_ Standards Announcement_ Non-binding Polls for VSLs Now Open - October 27-November 6 2010 _ Project 2007-23

Item_11d--Standards Announcement - Project 2007-23 _ Violation Severity Levels

Item_11d--Standards Announcement_ Results of Non-Binding Poll of VSLs _ Project 2007-23 Violation Severity Levels

Item_11e--FW_ Please Cast Your Vote Today for the Relay Loadability Order 733 Ballot _ Project 2010-13

Item_11e--Standards Announcement - Project 2010-13 - Relay Loadability Order 733 Modifications

Item_11e--Standards Announcement_ Project 2010-13 Relay Loadability for Order 733 - Successive Ballot Results

Item_11f--BOT memo updating on votong on PRC-023-2 and RSDP 20110309L

Item_11f--FW_ Please Cast Your Vote Today for the Relay Loadability Order 733 Ballot _ Project 2010-13

Item_11f--Standards Announcement - Recirculation Ballot Window Open February 24 - March 6 2011 _ Project 2010-13

Item_11f--Standards Announcement_ Project 2010-13 ndash Relay Loadability Order _ Recirculation Ballot Results

Item_13a--Unofficial_Comment_Form_for_Standards_Committee_Posting_of_Prioritization_Tool--2-10-11

Unofficial Comment Form for Standards Committeersquos Project Prioritization Reference Document and Tool


During the past few years the Standards Committee has been presented with more proposals for developing new or revised projects than can be accomplished at one time The project prioritization tool is an excel spreadsheet that provides a transparent


Item_13b--2007-12_BAL-003-1_Comment_Form--Submitted--3-7-11

Unofficial Comment Form for BAL-003-1 Frequency Response and Frequency Bias Standard


Item_13c--Submitted_3-7-11--Comment_Form--Project-2007-12_BAL-003-1



Item_13d--LP--Comments_Project2007-23_2-18-11 Submitted




Item_13e--LP--Submitted_3-7-11--Project_2006-06_RC_COMMENT_FORM_RSC--2-28-11

Comment Form for Reliability Coordination ndash Project 2006-06




Alternative Interpersonal Communication Any method Interpersonal Communication that is able to serve as a substitute for and is redundant to normal Interpersonal Communication and does not utilize the same infrastructure (medium) as normal Interpe

Item_13g--FW_ Draft CAN-0015 Unavailability of NERC Tools

Item_13h--Draft CAN-0016 CIP-001-1 R1 - Applicability to Non-BES

Item_13i--Draft CAN-0017 CIP-007 R5 System Access and Password Controls

Item_13j--FW_ Draft CAN-0018 FAC-008 R121 Terminal Equipment

Item_13k--Memo to Board on Section 1700 ROP changes FINALr

Item_13k--NERC memo on Section 1700 Following Comment Period

Item_13k--Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to Determinations

Item_13k--RE_ Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to Determinations

Member

Organization

Region

Segment Selection

1

Adamson Alan

New York State Reliability Council LLC

NPCC

10

2

Guy Zito

Northeast Power Coordinating Council

NPCC

10

3

Campoli Gregory

New York Independent System Operator

NPCC

2

4

Chong Kurtis

Independent Electricity System Operator

NPCC

2

5

Clermont Sylvain

Hydro-Quebec TransEnergie

NPCC

1

6

Dackow Bohdan M

US Power Generating Company (USPG)

NPCC

---

7

De Graffenried Chris

Consolidated Edison Co of New York Inc

NPCC

1

8

Dunbar Gerry

NPCC

NPCC

10

9

Evans-Mongeon Brian D

Utility Services

NPCC

8

10

Garton Mike

Dominion Resources Services Inc

NPCC

5

11

Gooder Brian L

Ontario Power Generation Incorporated

NPCC

5

12

Goodman Kathleen

ISO - New England

NPCC

2

13

Haswell Chantel

FPL Group Inc

NPCC

5

14

Kiguel David

Hydro One Networks Inc

NPCC

1

15

Lombardi Michael R

Northeast Utilities

NPCC

1

16

MacDonald Randy

New Brunswick Power Transmission

NPCC

1

17

Metruck Bruce

New York Power Authority

NPCC

6

18

Pedowicz Lee

NPCC

NPCC

10

19

Pellegrini Robert

The United Illuminating Company

NPCC

1

20

Saksena Saurabh

National Grid

NPCC

1

21

Schiavone Michael

National Grid

NPCC

1

22

Sipperly Wayne


NPCC

5

23

Weaver Donald

New Brunswick System Operator

NPCC

2

24

Wu Ben

Orange and Rockland Utilities

NPCC

1

25

Yost Peter


NPCC

3

Gerald W Cauley

President and Chief Executive Officer

David N Cook

Sr Vice President and General Counsel


116-390 Village Boulevard

Princeton NJ 08540-5721

(609) 452-8060

(609) 452-9550 ndash facsimile

s Willie L Phillips

Holly A Hawkins

Attorney

Willie L Phillips

Attorney


1120 G Street NW

Suite 990

Washington DC 20005-3801

(202) 393-3998

(202) 393-3955 ndash facsimile

Gerald W Cauley


David N Cook


North American Electric Reliability

Corporation



(609) 452-8060


Persons to be included on FERCrsquos service list are indicated with an asterisk NERC requests waiver of FERCrsquos rules and regulations to permit the inclusion of more than two people on the service list

Holly A Hawkins

Attorney

Willie L Phillips

Attorney


1120 G Street NW

Suite 990

Washington DC 20005-3801

(202) 393-3998


Gerald W Cauley


David N Cook



Corporation



(609) 452-8060


Holly A Hawkins

Attorney

Willie L Phillips

Attorney


1120 G Street NW

Suite 990


(202) 393-3998


- 2 - LRP 3162011 922 AM

4 Review Executive Tracking Summary (in Meeting Materials Package)

a Review entries

5 FERC (in Meeting Materials Package) a FERC Feb 17 2011 Meeting Agenda b FERC March 10 2011 Meeting Agenda Item NOPR Docket No Posted End Date When

Effective T1 Integration of Variable

Energy Resources Docket No RM10-11-000

22511 3111

T2 Fourth Quarter 2010 Compliance Filing Of The North American Electric Reliability Corporation In Response To Paragraph 629 Of Order No 693 And Request To Terminate Compliance Filing Obligation

Docket No RM06-16-000

22811

Item FERC Orders Docket No Posted Summary U1 Order Dismissing

Compliance Filing--Mandatory Reliability Standards for Critical Infrastructure Protection

RM06-22-014 31011 FERC dismisses NERCrsquos 9910 compliance filing in response to FERCrsquos 31810 Order regarding CIP Standards with respect to nuclear power plants as moot

- 3 - LRP 3162011 922 AM


a

b


a

8 Join Ballot Pools (in Meeting Materials Package)

a


a

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

Concept White Paper Comment Form (link to Word Version) Announcement


b Notice of proposed Changes to RFC Rules of

Procedure and Request for Comments


3111 41511

c Proposed Amendments to NERC Rules of Procedure Appendices 3B and 3D


3111 41511

d

Project 2010-07 - Generator Requirements at the Transmission Interface - Various BAL CIP EOP FAC IRO MOD PER PRC TOP and VAR standards

White Paper Attachment 1 Attachment 2 Announcement

Informal Comment Period--Click on Submit

Comments--Comments to be sent to

Malloryhugginsnercnet

3411 4411

- 4 - LRP 3162011 922 AM

e

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

EOP-004-2 Redline to last posted Comment Form (link to Word Version) Implementation Plan CIP-001-1 EOP-004-1 Announcement


Item 9a--Will not make NERCrsquos active project list 10 Reference Documents Posted For Comment

a

11 Concluded Ballots (in Meeting Materials Package) httpsstandardsnercnetBallotsaspx

(clicking in the column to the right of ldquoBallot Periodsrdquo column links to the Ballot Results)

Results of Ballot

RSC RecommendDate

a Project 2010-11 - TPL Table 1

Footnote B Recirculation

Ballot 12611 2511

Quorum 9361

Approval 8654

Yes 1511

b Project 2007-07 - Vegetation

Management - FAC-003


Non-Binding Poll

21811 22811

Quorum 7928

Approval 7934

Yes 22211

c



Quorum 8710

Approval 4954

Yes 3211

d Project 2007-23 - Violation

Severity Levels Non-binding

Poll 2911 21811

Ballot Pool 310

Opinions 141

Yes 102810

72 Support

- 5 - LRP 3162011 922 AM

e Project 2010-13 - Relay Loadability

Order - PRC-023


Non-Binding Poll

12411 21311

Quorum 8395

Approval 6571

Yes 21111

f Project 2010-13 - Relay Loadability Order - PRC-023


22411 3611

Quorum 8735

Approval 6883

Yes 21111

12 Posted For 30-Day Pre-Ballot Review (Open Ballot Pools) Between RSC

Meetings

a


a Standards Project Prioritization Reference Document and Tool

Comment Form

12111 21011

b Project 2007-12 - Frequency Response Comment

Form 2411 3711

c Project 2007-07 - Vegetation Management - FAC-003 Comment Form

12711 22811

d Project 2007-23 - Violation Severity Levels Comment

Form 12011 21811

e Project 2006-06 - Reliability Coordination - COM-001

COM-002 IRO-001 and IRO-014 Comment

Form 11811 3711

f Regional Reliability Standards - PRC-006-NPCC-1 -

Automatic Underfrequency Load Shedding

Comment Form

(no comments submitted)

11011 22411

g CAN-0015--Draft CAN-0015 Unavailability of NERC Tools Comments 2411 21811

h CAN-0016--Draft CAN-0016 CIP-001-1 R1 - Applicability to Non-BES

Comments 2411 21811

i CAN-0017--Draft CAN-0017 CIP-007 R5 System Access

and Password Controld Comments 21111 3411

j CAN-0018--Draft CAN-0018 FAC-008 R121 - Terminal

Equipment Comments 2411 21811

k Proposed Changes to Rules of Procedure to Add Section

1700 - Challenges to Determinations Comments 21411 3711

- 6 - LRP 3162011 922 AM


a


a

16 NERC Meetings (in Meeting Materials Package) a ERO-RAPA b MRC and BOT Meetings

1 Member Representatives Committee and Board of Trustees Meeting Feb 16-17 2011

2 Board of Trustees Conference Call March 10 2011 a The NERC 2011-2013 Workplan with the prioritized standards b The PRC-023-1 Standard (Relay Loadability) Phase 1 due to FERC

by March 16 2011 c The VSLs for the CIP Version 4 d A set of VSLs for various other standards

e The NERC filing in response to the FERC performance assessment was reviewed discussed and approved as an Informational filing for FERC due date for filing is March 18 2011

17 NERC RSG RRSWG (in Meeting Materials Package) a RSG Feb 14 2011 Conference Call agenda b RSG March 15 2011 Conference Call agenda

18 Standards Committee Report (in Meeting Materials Package) a Two Standards Committee Positions open Nominations closed March 8

2011 b Ballot results of the Standards Committee E-mail ballot of the proposed

Reliability Standards Development Plan 2011-2013 c Notes March 10 2011 Standards Committee Meeting 19 SCPS Meeting a SDT selection criteria 20 NERC Compliance Application Notices a Comments to the CAN process

21 NERC Bulk Electric System Definition (in Meeting Materials Package) a Drafting Team members b NERC Staff Comments on Bulk Electric System (BES) Concept

Document c Drafting Team meetings 1 March 2-4 2011 meeting

- 7 - LRP 3162011 922 AM

d Summary of Definition of BES Drafting Team meetings sent to the NPCC Board of Directors

1 Feb 9-11 2011 2 March 2-4 2011 e Work of the RBESDCG f Brian Evans-Mongeon presentationdiscussion

22 NPCC Regional Standards--Update (in Meeting Materials Package)

a Disturbance Monitoring (PRC-002-NPCC-01) 1 VSLs approved by NPCC membership NERC Board of Trustees

approved Nov 4 2010 Being prepared for FERC and Canadian Provincial authority filings



a Ten day ballot concluded on Jan 28 2011 Did not get quorum RSC remanded back to Drafting Team

b Drafting Team Meeting scheduled for March 21-22 2011 at the NPCC Offices to answer comments received to the NERC posting and address outstanding issues

c Special Protection System d Regional Reserve Sharing 1 Draft RSAR developed 2 TFCO soliciting for Drafting Team members


a Status of the filing 24 Directory and Regional Work Plan Status

a Directory effective dates Directory Number


Current Activity


Approved on 1212009

TFCP has charged CP11 with a comprehensive review of Directory 1 to include the triennial document review an examination of the NERC TPL standards the existing NPCC planning criteria and the implementation of Phase 2 of the Directory Project which will reformat existing Directory criteria into NERC style requirements CP11 received additional direction and feedback from TFCP at the February 2011 TFCP meeting CP11rsquos schedule calls for presenting a final draft to RCC in November 2011


Approved on 102108


- 8 - LRP 3162011 922 AM


Approved on 71108



Approved on 12109



TFCO Directory5 was approved by the Full Members on December 2 2010 TFCO working to resolve outstanding reserve issues associated with Directory 5 TFCO expects to post a revised version of Directory 5 to the Open Process this spring

6 New Reserve Sharing

TFCO TFCO considering draft of a new Directory on Regional Reserve Sharing which would replace C38 until a Regional Standard is developed TFCO expects to psot draft of Directory 6 this spring

7 (A-11)


Approved on 122707


8 (A-12)

System Restoration

Approved on 102108


9 (A-13)


Approved on 122208

Directories 9 and 10 have been identified to be reformatted in accordance with Phase 2 of the Directory Project Additionally TFCO to incorporate draft language that would revise section 70 to ensure that documentation is not sent to TFCO The next TFCO review is scheduled for July 2012


Approved on 122208

Refer to Directory 9 preceding


Approved on 62609


- 9 - LRP 3162011 922 AM

25 Review RFC MRO Standards Relevant to NPCC (in Meeting Materials

Package) a RFC Standards Under Development webpage

httpsrsvprfirstorgdefaultaspx b RFC Standard Voting Process (RSVP) webpage ReliabilityFirst Corporation - Reliability Standards Voting Process MOD-025-RFC-01 - Verification and Data Reporting of Generator Gross

and Net Reactive Power Capability passed its 15 day Category vote and was approved by the RFC Board of Directors at their March 3 2011 Meeting

Standard Under


1

2





26 Report on NERC NAESB and Regional Activities (in Meeting Materials

Package) a Report on NERC NAESB and Regional Activities 1 Jan 31 2011 2 Feb 28 2011

27 Task Force Assignments





2

- 10 - LRP 3162011 922 AM

28 Future Meetings and Other Issues (in Meeting Materials Package)

a Department of Energy Launches Cyber Security Initiative b FERC Cybersecurity Efforts c Severe Impact Resilience Task Force (SIRTF) formed d Remarks of Gerry Cauley to the House Armed Services Committee

Subcommittee on Emerging Threats and Capabilities e NERC Critical Infrastructure Protection Committee Dec 8-9 2010

Meeting Minutes f Draft for Comment NPCC Board Minutes 2-8-11 Meeting and NERC MRC

and BOT Summary Notes g Draft 7 of SERC Underfrequency Load Shedding Standard Posted for

Comments Due March 24 2011 h SPP RE UFLS Regional Standard- Balloting Results-Proposed Standard

Fails i CIP implementation questions

j Cyber Attack Task Force Formed as Part of Coordinated Action Plan k Presentations from the 2011 NARUC Winter Committee Meetings httpwwwnarucorgmeetingpresentationscfm92 l NERC Operating Committee March 8-9 2011 Meeting--notes m NERC Planning Committee March 8-9 2011 Meeting--notes



October 19-20 2011 Boston Massachusetts




April 1 2011 August 19 2011 April 15 2011 Sept 2 2011 April 29 2011 Sept 16 2011 May 13 2011 Sept 30 2011 June 3 2011 Oct 28 2011 June 17 2011 Nov 10 2011 (Thursday) July 1 2011 Dec 16 2011 July 15 2011 Dec 30 2011

- 11 - LRP 3162011 922 AM


May 3 2011 Teleconference September 20 2011 NPCC June 30 2011 NPCC October 26 2011 Teleconference

July 28 2011 Teleconference November 30 2011 Toronto


RCC June 1 Sept 8 Nov 29 CC April 13 May 16 June 14-15 July 13

August 17 Sept 21-22 Oct 19 Nov 16 Dec 13-15

TFSS TFCP May 11 August 17 Nov 2 TFCO April 14-15 August 11-12 Oct 6-7 TFIST TFSP March 22-24 May 24-26 July 19-21

Sept 27-29 Nov 15-17

- 12 - LRP 3162011 922 AM

Joint Meeting With CC

1 Directory Revision Schedule 2 NPCC Compliance Schedule for 2011 and 2012 3 CCRSC Involvement with Review of Directories 4 Directory Format to clearly identify more Stringent NPCC Criteria 5 CANs enforcement 6 Transformation of the NPCC Directories and other Criteria Documents that

support the non-approved NERC fill-in-the blank standards into Regional Reliability Standards

Examples

Directory 1MOD-11 amp MOD-13

Directory 12 PRC-006 (Continent Wide UFLS once approved) and the presently approved PRC-007 (to be retired by Project 2007-1)

Directory 9 MOD-024-1

Directory 10MOD-025-1

7 Original intent of FERC Order 693 was for NERCRegions to produce Regional Standards to replace-fill-in-the-blank standards

8 Status of Standard PRC-006-NPCC-1 Automatic Underfrequency Load Shedding

9 Progress on the proposed revisions for Directory 12 and the proposed revisions to the Directory 12 Implementation Plan approved by TFSS

10 The Policy of continued use of NPCC Task Forces in the development of new Criteria in the present timeframe in which NERC is accelerating its roll out of more stringent enforceable Standards

Example - Proposed PRC-005-2 and Directory 3 - Is a more specific or more stringent protection system maintenance really needed within NPCC

Respectfully Submitted Guy V Zito Chair RSC Assistant Vice President-Standards

- 13 - LRP 3162011 922 AM


Northeast Power Coordinating Council Inc (NPCC)

Antitrust Compliance Guidelines






competitor


- 14 - LRP 3162011 922 AM

Action Item List

Action Item

Number

Agenda Item


32 16b To discuss with Herbert Schrayshuen how HQ because of its unique operational requirements will be addressed in standards development


RSC Meeting








Feb 17-18 2009

June 17-18 2009

August 6-7 2009



Ongoing

61 21 Notify NPCC Drafting Team members that the RSC is available for advice at any time


Ongoing

- 15 - LRP 3162011 922 AM

Action Item

Number

Agenda Item


and that they will be invited to call in with status reports

Sept 24-25 2009

Nov 4-5 2009

April 21-22 2010




session April 21 2010 Ongoing Joint RSCCC Meeting this

meeting Ralph Rufrano rejoined the RSC in the

capacity of NPCC Compliance liaison Comments not to be

submitted on the CCEP

June 29-30 2010


NPCC Members on NERC Drafting Teams list Saurabh Saksena to maintain Will get input from Carol Sedewitz

RSC RSC Meeting

Ongoing

August 18-19 2010

- 16 - LRP 3162011 922 AM

Action Item

Number

Agenda Item




Provide update



RSC Meeting


Nov 30 2010 Dec 2 2010



RSC Meeting



Feb 2-3 2011

70 20 Talk to Stan Kopman and the CC about the process for submitting comments after Valerie Agnew (NERC) drafts CANs for their first posting Industry will have two weeks for comments


RSC Meeting

71 ---- Talk to Compliance about Reliability Standard RSAWs


- 17 - LRP 3162011 922 AM

Action Item

Number

Agenda Item


There should be a Compliance Committee representative on the Drafting Team

72 ---- Find out what other Regions are doing regarding interpretations


73 ---- Discuss consistency with the RSG



Regional Reliability Standards Development Procedure Process Manual

Approved by NPCC Board of Directors September 19 2007

Approved by NERC BOT October 23 2007 Adopted by FERC March 21 2008

1

NPCC

REGIONAL RELIABILITY STANDARDS DEVELOPMENT PROCEDUREPROCESS MANUAL

TABLE OF CONTENTS

NO TABLE OF CONTENTS ENTRIES FOUNDERROR NO TABLE OF CONTENTS ENTRIES FOUNDI EXECUTIVE SUMMARY 2

II REGIONAL RELIABILITY STANDARD DEVELOPMENT PROCEDURE 1 CHARACTERISTIC ATTRIBUTES 2 2 ELEMENTS OF A REGIONAL STANDARD 5 3 TERMS AND FUNCTIONS 8 4 PROCEDURE DESCRIPTION 10 5 FLOWCHART 15 6 ERO AND REGULATORY APPROVALS 16

7 APPEALS 16 III APPENDIX

A) RSAR FORM 19

2

Formatted Indent Left 0 Hanging 025Numbered + Level 1 + Numbering Style I IIIII hellip + Start at 1 + Alignment Left + Alignedat 025 + Indent at 075

3

I I EXECUTIVE SUMMARY The purpose of the Northeast Power Coordinating Council Inc (NPCC) is to enhance the reliability of the international interconnected bulk power system in Northeastern North America through the development of more stringent and specific regional reliability standards and compliance assessment and enforcement of continent-wide and regional reliability standards pursuant to the execution and implementation of a Regional Delegation Agreement with the Electric Reliability Organization (ERO) and applicable Canadian Memoranda of Understanding that are backstopped by the Federal Energy Regulatory Commission (FERC) and Canadian Provincial authorities In the development and enforcement of Regional Reliability Standards NPCC to the extent possible facilitates attainment of fair effective efficient and competitive electric markets

General Membership in NPCC is voluntary and is open to any person or entity including any entity participating in the Registered Ballot Body of the ERO that has an interest in the reliable operation of the Northeastern North American bulk power system

The This NPCC Regional Reliability Standards Development ProcedureProcess Manual describes the procedures policies and practices approved by NPCC members and implemented to ensure an ldquoopen fair and inclusiverdquo process for the transparent initiation development implementation and revision of NPCC Rregional Rreliability Sstandards (regional standards) necessary for the reliable operation of the international and interconnected bulk power system in Northeast North America These Sstandards will in all cases not be inconsistent with or less stringent than any requirements of the North American Electric Reliability CouncilElectric Reliability Organization (NERCERO) Reliability Standards The procedure will not unnecessarily delay the development of the proposed reliability standards Each regional reliability standard shall enable or support one or more of the-NERCERO reliability principles1

II REGIONAL RELIABILITY STANDARD DEVELOPMENT PROCEDUREPROCESS MANUAL

thereby ensuring that each standard serves a purpose in support of the reliability of the regional bulk power system Each standard shall also be consistent with all of pertinent reliability principles and criteria thereby ensuring that no standard undermines reliability through as an unintended consequence

The NPCC Regional Reliability Standards Development ProcedureProcess Manual is

1 CHARACTERISTIC ATTRIBUTES

bull Open mdash The NPCC Regional Reliability Standards Development ProcedureProcess Manual provides any person the ability to participate in the development of a standard Anyor entity that is directly and materially affected by the reliability of the NPCCrsquos bulk power system has the ability to participate in the development and approval of reliability standards NPCC


Comment [kbc1] Very longwindede COnsider revising

Comment [kbc2] See general note about consistency in the text box at the end of the document and make appropriate changes throughout the document if agree with this approach

Comment [kbc3] Why do we need this Consider deleting


Comment [kbc4] Dont agree with change This manual describes the process

Formatted Indent Left 025 Hanging 025 Dont adjust space between Latin andAsian text

Comment [kbc5] Dont agree the manual describes the process so changed to Process

Comment [kbc6] Some repetition revised to remove


4

utilizes a website to accomplish this Online posting and review of standards and the real time sharing of comments uploaded to the website allow complete transparency There are no undue financial barriers to participation Participation in the open comment process is not conditional upon membership in the ERO NPCC or any organization and participation is not unreasonably restricted on the basis of technical qualifications or other such requirements There are no undue financial barriers to participationNPCC utilizes a website to accomplish this Online posting and review of standards and the real time sharing of comments uploaded to the website allow complete transparency

bull Inclusive mdash The NPCC Regional Reliability Standards Development ProcedureProcess Manual provides any person with a direct and material interest the right to participate by expressing an opinion and its basis have that position considered and in the event they are not satisfied with the response to their opinion appealed the response through an established appeals process if adversely affecteddesired

bull Balanced mdash The NPCC Regional Reliability Standards Development ProcedureProcess Manual has seeks to achieve a balance of interests and all those entities that are directly and materially affected by the reliability of the NPCCrsquos bulk power system are welcome to participate and shall not be dominated by any two interest categories and no single interest category shall be able to defeat a matter This will be accomplished through the NPCC Bylaws 2

bull Fair Due Process mdash The NPCC Regional Reliability Standards Development ProcedureProcess Manual provides for reasonable notice and opportunity for public comment The procedure includes public notice of the intent to develop a standard a 45 calendar day public comment period on the proposed standard request or standard with due consideration of those public comments and responses to those comments will to be posted on the NPCC website A final draft of the notice of intent to develop the standard or the draft standard itself will be posted for a 30 calendar day pre-balloting period and thenafter which a ballot of NPCC Members will be conducted Upon approval by the NPCC Members the NPCC Board then votes to approve submittal of the Regional Reliability Standard to NERC

which defineing eight six sectors (categories) for voting All individuals and entities that are directly and materially affected by the reliability of the NPCCrsquos bulk power system are welcome to participate

bull Transparent mdash All actions material to the development of Regional Reliability Standards are transparent and information regarding the progress of a standards development action is made available to the public through postingsed on the NPCC website as well as through extensive email lists

In as much as NPCC is one of several regional entities within the Eastern Interconnection of North America there will be no presumption of validity by the ERO for any NPCC Regional Reliability Standard In order to receive the approval of

2 Available on the NPCC website wwwnpccorg

Comment [kbc7] Moved for better flow of ideas


Comment [kbc9] Needed



Comment [kbc12] The appellant need not be adversely affected must they


Comment [kbc14] We recall that the number of sectors is to be reduced from 8 to 6 Please confirm If Bylaws will not be amended to reflect this before themanual is approved leave as 8 and revise later



Field Code Changed


5

the ERO the NPCC Reliability Standards Development Process must also achieve the following objectives

bull No Adverse Impact on Reliability of the Interconnection mdash An NPCC

Regional Reliability Standard provides a level of bulk power system reliability that is necessary and adequate to protect public health safety welfare and North American security and will not have an adverse impact on the reliability of the Interconnection or other Regions within the Interconnection

bull Justifiable Difference mdash An NPCC Regional Reliability Standard is based

on justifiable differences between Regions such as different electrical systems or facilities sensitivity of load to disruptions sensitivity of generation to disruptions frequency and voltage sensitivity system operating limit development and facilities ratings process electrical system interactions etc

bull Uniformity- mdash NPCC Regional Reliability Standards shall provide for as

much uniformity as possible with reliability standards across the interconnected bulk power system of the North American continent A NPCC Reliability Standard shall be more stringent than a continent-wide reliability standard may include a regional variation that addresses matters that the continent-wide reliability standard does not or shall be a regional difference necessitated by a physical difference in the northeastrsquos bulk power system3

where the interpretation of the phrase ldquophysical differencerdquo will be consistent with FERCrsquos Order issued September 22 2004 Granting Request For Clarification regarding Docket No PL04-5-000 Policy Statement on Matters Related to Bulk Power System Reliability

bull No Undue Adverse Impact on Commerce mdash An NPCC Regional Reliability Standard will not cause any undue adverse impact on business activities that are not necessary for reliability of the Region and its interconnected Regions All regional reliability standards shall be consistent with NERCrsquos market principles4

Other Attributes provisions of the NPCC Regional Reliability Standards Development ProcedureProcess Manual include

bull Maintenance of Regional Reliability Standards - NPCC Regional

Reliability Standards will be reviewed for possible revision at least every three years after FERC approval and follow the same process as in the case of a new standard If no changes are warranted the Regional Standards Committee (RSC) shall recommend to the NPCC Board that the standard be reaffirmed If the review indicates a need to revise or withdraw a standard a Regional Standard Authorization Request shall be prepared by the RSC and submitted in accordance with the NPCC Regional Reliability Standards Process The old

3 The interpretation of the phrase ldquophysical differencerdquo will be consistent with FERCrsquos Order issued

September 22 2004 Granting Request For Clarification regarding Docket No PL04-5-000 Policy Statement on Matters Related to Bulk Power System Reliability


Formatted Highlight

Comment [kbc16] There are two ways to approach using the indefinite article when placed in from of an acronym We just need to be consistent throughout the document I have flagged the cases I have seen

Formatted Highlight

Formatted Highlight

Comment [kbc17] Very unwieldy We have made this a footnote

Formatted Highlight





Comment [kbc18] We recommend moving this entire section and inserting it after the process for developing a new standard is described That way all of the players involved would have been described as well as the process for developing the new standard Also each of these three items should be placed in a separate section and written as a process with a flowchart included for each as necessary These changes should help to minimize some of the repetition that exists in the document as currently structured

Comment [kbc19] By whom See general comments in the text box on page 2

Comment [kbc20] From FERC (and Canadian Authority) approval or from NERC BOT approval Need to make this clear so a date can be clearly defined Since there can be





6

existing approved standard subject to revision will remain in place effect until such time as the revised version has received FERC or applicable Canadian Regulatory Authority approvals as appropriate passed through the entire process at which point the old standard it will be retired in accordance with any applicable new implementation plan associated with the newly approved regional revised standard The review process shall be conducted by soliciting comments from the stakeholders and through open posting on the NPCC website If no changes are warranted Regional Standards Committee (RSC) shall recommend to the NPCC Board that the standard be reaffirmed If the review indicates a need to revise or withdraw a standard a regional standard authorization request shall be prepared by the RSC and submitted in accordance with the standards development process contained in this procedure

bull Maintenance of the Regional Reliability Standards Development

ProcedureProcess Manual - This NPCC Regional Reliability Standards Development ProcedureProcess Manual will be reviewed for possible revision at least once every five years or more frequently if needed and subject to the same procedure as that ofapplies to the development of a regional standard All such revisions shall be subject to approval by the NPCC Board NERC FERC and could be subject to approval if required by applicable authorities in Canada The NPCC RSC has the authority to make non-substantive changes to this procedure and subsequently notify the NPCC Board for their concurrence at the Boardrsquosir next scheduled meeting

bull Interpretation of Standards - All persons who are directly and materially

affected by the NPCCrsquos bulk power system reliability shall be permitted to request an interpretation of an NPCC regional reliability standard The person requesting an interpretation will shall send an email request to the Regional Standards Process Manager (RSPMManager of Reliability Standards) as noted on the NPCC website explaining the specific circumstances surrounding the request and what clarifications are required as applied to those circumstances The request should shall indicate the material impact to the requesting party or others caused by the lack of clarity or a possibly incorrect interpretation of the regional standard The RSPMManager of Reliability Standards along with guidance from the RSC will forward the request to the originating Task Force to whom responsibility was originally assigned for which acted as the drafting team for that regional reliability standard The Task Force will address through a written response the request for clarification as soon as practical but not more than 45 business days from its receipt by the Task Force This written interpretation will be posted along with the final approved and adopted regional standard and will stand until such time as the regional standard is revised through the normal RSAR process at which time the regional standard will be modified to incorporate the clarifications provided by the interpretation

2 ELEMENTS OF A RELIABILITY STANDARD

bull Elements of a Regional Reliability Standard

Comment [kbc22] When does the process come to an end After FERC or NERC BOT this gives the impression that after NERC BOT adoption the standard will become effective Better to say after FERC or applicable Canadian Regulatory approvals or something similar

Comment [kbc23] Not strictly necessary since weve already said above that well be following the same process as for a new standard Reinstate if deemed necessary

Comment [kbc24] From when FERC date

Comment [kbc25] Too much detail since this will be repeated in Section 4 Prune this down

Formatted Highlight

Formatted Highlight

Comment [kbc26] why specify

Comment [kbc27] Stronger

Comment [kbc28] Should there be a step here for RSC or MRS review

7

To ensure uniformity of regional reliability standards and notavoid inconsistentcy with NERC continent-wide standards a regional reliability standard shall consist of the elements identified in this section of the procedure These elements are intended to apply a systematic discipline in the development and revision of regional standards This discipline is necessary to for achieving regional standards that are measurable enforceable and consistent as well as results-oriented56

ie

Performance-based Risk-based and CompetencyCapability-based

as well as being measurable enforceable and consistent The Standard Drafting Team (SDT) should strive to achieve a portfolio of performance risk and competencycapability-based mandatory reliability requirements that support an effective defense-in-depth strategy Each requirement should identify a clear and measurable expected outcome such as a) a stated level of reliability performance b) a reduction in a specified reliability risk or c) a necessary competency a) Performance-based - defines a specific reliability objective or outcome that has a direct observable effect on the reliability of the bulk power system ie an effect that can be measured using power system data or trendsdefines a particular reliability objective or outcome to be achieved In its simplest form a results-based requirement has four components who under what conditions (if any) shall perform what action to achieve what particular result or outcome b) Risk-based - defines actions of entities that reduce a stated risk to the reliability of the bulk power system and can be measured by evaluating a particular product or outcome resulting from the required actionspreventive requirements to reduce the risks of failure to acceptable tolerance levels A risk-based reliability requirement should be framed as who under what conditions (if any) shall perform what action to achieve what particular result or outcome that reduces a stated risk to the reliability of the bulk power system c) CompetencyCapability-based - defines capabilities needed to perform reliability functions and can be measured by demonstrating that the capability exists as requireddefines a minimum set of capabilities an entity needs to have to demonstrate it is able to perform its designated reliability functions A competency-based reliability requirement should be framed as who under what conditions (if any) shall have what capability to achieve what particular result or outcome to perform an action to achieve a result or outcome or to reduce a risk to the reliability of the bulk power system All mandatory requirements of a regional reliability standard shall be within the standard document Supporting documents to aid in the implementation of

5 Results-based Standards see httpwwwnerccomfilezstandardsProject2010-06_Results-

based_Reliability_Standardshtml 6 Results-based Standards presentation see httpwwwnerccomfilesResults-Based-Standards-

102010pdf

Formatted Superscript

Formatted Bulleted + Level 3 + Aligned at 125 + Tab after 15 + Indent at 15



Comment [kbc29] See consistency comment in text box

Comment [kbc30] Need something stronger or more definitive


8

a standard may be referenced by the standard but are not part of the standard itself The most current version of the approved NERC Reliability Standard template and its associated elements as or if applicable will be used at the time of the development of the NPCC Regional Reliability Standard to ensure all essential elements are contained therein to achieve consistency and uniformity and meet all statutory requirements A sample of the elements contained in the standard appears in Table 1 below however the latest ERO Board approved Standard template that may be found on the NERC website will supersede the list below at the time the regional standard is developed

Each regional reliability standard shouldshall enable or support one or more of the reliability principles as identified in the most recent set posted on the NERC website (see below) Each reliability standard shouldshall also be consistent with all of the reliability principles The intent of the set of NPCC regional reliability standards is to deliver an Adequate Level of Reliability as defined by NERC

a) 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 and Regional Reliability Standards Directories and Criteria

b) 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

c) 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

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

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

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

g) The reliability of the interconnected bulk power systems shall be assessed monitored and maintained on a wide-area basis

h) Bulk power systems shall be protected from malicious physical or cyber attacks

Recognizing that bulk power system reliability and electricity markets are inseparable and mutually interdependent all regional reliability standards shall be


Formatted Indent Left 125 SpaceBefore 12 pt

Formatted Space Before 12 pt

9

consistent with the most recent set of mMarket iInterface pPrinciples as posted on the NERC website Consideration of the mMarket iInterface pPrinciples is intended to ensure that regional reliability standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets Elements of a Regional Reliability Standard A regional reliability standard includes several components designed to work collectively to identify what entities must do to meet their reliability-related obligations as an owner operator or user of the bulk power system The components of a regional reliability standard include mandatory and enforceable sections and informational sections of the standard Mandatory and Enforceable Sections of a Standard Title A brief descriptive phrase identifying the topic of the standard Number A unique identification number assigned in accordance with a published classification system to facilitate tracking and reference to the standards Purpose The reliability outcome achieved through compliance with the requirements of the standard Applicability Effective Dates Identification of when each requirement becomes effective in each jurisdiction Requirement An explicit statement that identifies the functional entity responsible the action or outcome that must be achieved any conditions achieving the action or outcome and the reliability-related benefit of the action or outcome Each requirement shall be a statement for which compliance is mandatory Measure Provides identification of the evidence or types of evidence needed to demonstrate compliance with the associated requirement Each requirement shall have at least one measure Each measure shall clearly refer to the requirement(s) to which it applies Evidence Retention Identification for each requirement in the standard of the entity that is responsible for retaining evidence to demonstrate compliance and the duration for retention of that evidence Variance A requirement (to be applied in the place of the continent-wide requirement) and its associated measure and compliance information that is applicable to a specific geographic area or to a specific set of functional entities Informational Sections of a Standard Application Guidelines Guidelines to support the implementation of the associated standard Procedures Procedures to support implementation of the associated standard Time Horizon The time period an entity has to mitigate an instance of violating the associated requirement4 Compliance Enforcement Authority The entity that is responsible for assessing performance or outcomes to determine if an entity is compliant with the associated standard

Comment [kbc31] Are these Market Interface Principles general enough that they apply to Canadian markets Can we include language to cater for Canadian market principles

Comment [kbc32] This looks like a cut and paste from the NERC Standards Process Manual so no editing done here Major reformatting is required

Comment [kbc33] Is this the end of the mandatory and enforceable section Heading required to indicated informationand a compliance section

10

Compliance Monitoring and Assessment Processes Identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated standard Additional Compliance Information Any other information related to assessing compliance such as the criteria or periodicity for filing specific reports Compliance Elements Associated with a Standard Violation Risk Factors and Violation Severity Levels Violation risk factors (VRFs) and violation severity levels (VSLs) are used as factors when determining the size of a penalty or sanction associated with the violation of a requirement in an approved reliability standard5 Each requirement in each reliabilityregional standard has an associated VRF and a set of VSLs VRFs and VSLs are developed by the drafting team working with NERCNPCC staff at the same time as the associated regional reliability standard but are not part of the reliabilityregional standard The NPCC Board of TrusteesDirectors is responsible for approving VRFs and VSLs Violation Risk Factors VRFs identify the potential reliability significance of non-compliance with each requirement Each requirement is assigned a VRF in accordance with the latest approved set of VRF criteria6 Violation Severity Levels VSLs define the degree to which compliance with a requirement was not achieved Each requirement shall have at least one VSL While it is preferable to have four VSLs for each requirement some requirements do not have multiple ldquodegreesrdquo of non-compliant performance and may have only one two or three VSLs Each requirement is assigned one or more VSLs in accordance with the latest approved set of VSL criteria7

The most current version of the approved NERC Reliability Standard template and its associated elements as or if applicable will be used at the time of the development of the NPCC Rregional Rreliability Sstandard to ensure all essential elements are contained therein to achieve consistency and uniformity and meet all statutory requirements

Table 1- Elements of a Regional Reliability Standard [update or delete]

Identification Number

A unique identification number assigned in accordance with an administrative classification system to facilitate tracking and reference (ie ldquoNPCC- BAL-002-0-Daterdquo which refers to NPCC Regional Standard referencing NERC BAL-002 Version 0 with NPCC Effective Date-final adoption by all Regional Authorities)

Title A brief descriptive phrase identifying the topic of the standard

Applicability Clear identification of the functional classes of entities responsible for complying with the standard noting any specific additions or exceptions

Formatted Highlight

Comment [kbc34] Will we maintain footnote from NERC document

Comment [kbc35] Is this how we envisage the process to work in NPCC

Formatted Highlight

Comment [kbc36] Will we maintain footnote

Comment [kbc37] Maintain footnote

11

The standard will be applicable to the Bulk Power System unless otherwise noted

Effective Date and Status

The effective date of the standard or prior to approval of the standard the proposed effective date If the effective date is tied to a regulatory approval the verbal formula indicating when the Regional standard is to become effective

Purpose The Results-Based purpose of the standard The purpose shall explicitly state what outcome end result will be achieved or is expected by from this Regional standard

Requirement(s) Explicitly stated Results-Based technical performance and preparedness requirements Each requirement identifies what entity is responsible and what action is to be performed or what outcome result is to be achieved Each statement in the requirements section shall be a statement for which compliance is mandatory

Risk Factor(s)

The potential reliability significance of each requirement designated as a High Medium or Lower Risk Factor in accordance with the criteria listed below

A High Risk Factor requirement (a) is one that if violated could directly cause or contribute to bulk power system instability separation or a cascading sequence of failures or could place the bulk power system at an unacceptable risk of instability separation or cascading failures or (b) is a requirement in a planning timeframe that if violated could under emergency abnormal or restorative conditions anticipated by the preparations directly cause or contribute to bulk power system instability separation or a cascading sequence of failures or could place the bulk power system at an unacceptable risk of instability separation or cascading failures or could hinder restoration to a normal condition

A Medium Risk Factor requirement (a) is a requirement that if violated could directly affect the electrical state or the capability of the bulk power system or the ability to effectively monitor and control the bulk power system but is unlikely to lead to bulk power system instability separation or cascading failures or (b) is a requirement in a planning timeframe that if violated could under emergency abnormal or restorative conditions anticipated by the preparations directly affect the electrical state or capability of the bulk power system or the ability to effectively monitor control or restore the bulk power system but is unlikely under emergency abnormal or restoration conditions anticipated by the preparations to lead to bulk power system instability separation or cascading failures nor to hinder restoration to a normal condition

A Lower Risk Factor requirement is administrative in nature and (a) is a requirement that if violated would not be expected to affect the electrical state or capability of the bulk power system

12

or the ability to effectively monitor and control the bulk power system or (b) is a requirement in a planning time frame that if violated would not under the emergency abnormal or restorative conditions anticipated by the preparations be expected to affect the electrical state or capability of the bulk power system or the ability to effectively monitor control or restore the bulk power system

Measure(s) Each requirement shall be addressed by one or more measures Measures are used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measure will identify to whom the measure applies and the expected level of performance or outcomes required demonstrating compliance Each measure shall be tangible practical and as objective as is practical It is important to realize that measures are proxies to assess required performance or outcomes Achieving the measure should be a necessary and sufficient indicator that the requirement was met Each measure shall clearly refer to the requirement(s) to which it applies

Table 2 Compliance Elements of a Regional Reliability Standard Compliance Monitoring Process

Defines for each measure

bull The specific data or information that is required to measure performance or outcomes

bull The entity that is responsible for providing the data or information for measuring performance or outcomes

bull The process that will be used to evaluate data or information for the purpose of assessing performance or outcomes

bull The entity that is responsible for evaluating data or information to assess performance or outcomes

bull The time period in which performance or outcomes is measured evaluated and then reset

bull Measurement data retention requirements and assignment of responsibility for data archiving

bull Violation severity levels Supporting Information Elements Interpretation Any interpretation of regional reliability standard that is

developed and approved in accordance with the ldquoInterpretation of Standardsrdquo section of Appendix A of this procedure to expound on the application of the standard for unusual or unique situations or to provide clarifications

Implementation Each regional reliability standard shall have an associated

13

Plan implementation plan describing the effective date of the standard or effective dates if there is a phased implementation The implementation plan may also describe the implementation of the standard in the compliance program and other considerations in the initial use of the standard such as necessary tools training etc The implementation plan must be posted for at least one public comment period and is approved as part of the ballot of the standard

Supporting References

This section references related documents that support reasons for or otherwise provide additional information related to the regional reliability standard Examples include but are not limited to

bull Glossary of terms

bull Developmental history of the standard and prior versions

bull Notes pertaining to implementation or compliance

bull Standard references

bull Standard supplements

bull Procedures

bull Practices

bull Training references

bull Technical references

bull White papers

bull Internet links to related information

Formatted Normal Indent Left 025Numbered + Level 1 + Numbering Style 1 23 hellip + Start at 2 + Alignment Left + Alignedat 05 + Tab after 075 + Indent at 075 Dont adjust space between Latin andAsian text Dont adjust space between Asiantext and numbers Tab stops 05 List tab +Not at 075

14

3 3 KEY PARTICIPANTS ROLES TERMS AND FUNCTIONS

bull NPCC Board of Directors (BOD Board) - The NPCC BOD shall consider for adoption regional reliability standards definitions variances and interpretations and associated implementation plans that have been processed according to the processes identified in this manual In addition the bBoard shall consider for approval VRFs and VSLs associated with each approved regional standard Once the BOD adopts a regional reliability standard definition variance or interpretation or implementation plan or once the BOD approves VRFs or VSLs the Bboard shall direct NPCC staff to submit the document(s) for approval by the NERC Board of Trustees

bull NPCC Members - The ballot body is comprised of all entities or individuals that

qualify for one of the stakeholder sectors within NPCC and as approved bystated in the NPCC BODBylaws All General and Full Members of NPCC can participate in the balloting of regional standards

bull Regional Standards Committee (RSC)mdashAn NPCC committee BOD -

appointed committee charged with management and oversight of the NPCC Regional Reliability Standards Procedure Process for development of regional standards VRFs VSLs definitions variances interpretations and implementation plans in accordance with this manual under a the sector based voting structure as described in the NPCC Bylaws

The RSC is an open and balanced stakeholder committee inclusive of all stakeholder interests that provide for or are materially impacted by the reliability of the bulk power system Its responsibilities are defined in detail in the NPCC RSC Scope

bull The NPCC RSC will consider requests for new or revised regional reliability standards and be available for advisement to the NPCC Board BOD on theregional standards and standards related issues in general

The RSC may not itself materially modify mandatory and enforceable sections of the a regional standard except without issuing a new notice to stakeholders regarding a vote of the modified standard Any RSC action will only be activated in the event of a minor corrections of to a the standard such as errata The RSC may make or revisions to the sections of the regional standard that are not mandatory and enforceable The RSC is responsible for managing the standards processes for development of standards VRFs VSLs definitions variances and interpretations in accordance with this manual The responsibilities of the RSC are defined in detail in the NPCC RSC Scope The RSC is responsible for ensuring that the regional standards VRFs VSLs definitions variances and interpretations and implementation plans developed by drafting teams are developed in accordance with the processes in this manual and meet NERCrsquos and FERCrsquos benchmarks for reliability standards including criteria for all governmental approvals


Formatted Font Bold



Comment [kbc38] For consistency with whats stated on page 4



Formatted List Paragraph No bullets ornumbering Adjust space between Latin andAsian text Adjust space between Asian textand numbers


Comment [kbc40] Reference needed

Formatted Indent Left 075 No bullets ornumbering

Comment [kbc41] Not necessary since the RSC itself does not change the standard even after issuing this notice

Comment [kbc42] We need to describe guidelines or criteria for these modifications to be undertaken by the RSC and the process to be followed including some notification to members and request for comments Revisions to the compliance elements of a regional standard say without stakeholder notice and input could be controversial



Comment [kbc43] The process for developing VRFs and VSLs is not described





Comment [kbc44] Whats this Clarification needed


Comment [kbc45] Reference needed()

15

The RSC is an open and balanced stakeholder committee inclusive of all stakeholder interests that provide for or are materially impacted by the reliability of the bulk power system

The RSC disposition regarding the rRegional sStandard aAuthorization rRequest (RSAR) which will in all cases be within 60 calendar days of receipt of a completed standard requestRSAR shall includebe one of the following

bull Accept the standard request as a candidate for development of a new standard revision of an existing standard or deletion of an existing standard The RSC may at its discretion expand or narrow the scope of the standard request under consideration The RSC shall prioritize the development of standards in relation to other proposed standards as may be required based on the volume of requests and resources

bull Reject the standard request If the RSC rejects a standard request a written explanation for rejection will be delivered to the requester within 30 calendar days of the decision

bull Remand the standard request back to the requester for additional work The NPCC standards process managerstaff will make reasonable efforts to assist the requester in addressing the deficiencies identified by the RSC The requester may then resubmit the modified standard request using the process above The requester may choose to withdraw the standard request from further consideration prior to acceptance by the RSC

The NPCC Standard Process responsibilities of the RSC will include

bull Review of NPCC Draft Standards (for such factors as completeness sufficient detail rational result and compatibility with existing NERC and other Regional standards) and clarifying standard development issues not specified in this procedure Under no circumstance will the RSC unilaterally make anysubstantial changes to the substancemandatory and enforceable sections essence of a draft standard

bull Ensure that the drafting team has given Ddue consideration to the work of the drafting team as well as the comments of stakeholders and minority objections in approving a proposed regional reliability standard to go to ballot

bull Approve standards for pre-ballot posting under a sector based voting structure as described later in the NPCC Inc Bylaws or


bull NPCC Standards Staff mdash- The standards staff led by the Assistant Vice-

President of Standards is responsible for administering NPCCrsquos Rregional rReliability sStandards pProcesses in accordance with this manual The standards staff provides support to the RSC in managing the standards processes and in supporting the work of all regional drafting teams The


Comment [kbc47] Here weve started getting into process details which are repeated in the process description later on (Steps 1 amp 2) Suggest removing this paragraph and the next 3 bullets and placing withing the section describing steps 1 amp 2

Comment [kbc48] Shouldnt this be an NPCC staff function Does RSC have the resources to do this

Comment [kbc49] Repetition See above Delete one occurrence

Comment [kbc50] If the TF is involved in drafting the regional standard who would this work










16

standards staff works to ensure the integrity of the standards processes and consistencyt of quality and completeness of the reliabilityregional standards through drafting team support and conducting quality reviews The standards staff facilitates all steps in the development of regional standards definitions variances interpretations and associated implementation plans The standards staff works with drafting teams in developing VRFs and VSLs for each regional standard The standards staff is responsible for presenting regional standards definitions variances and interpretations and associated implementation plans to the NPCC BOD for adoption When presenting standards-related documents to the NPCC BOD for adoption or approval the standards staff shall report the results of the associated stakeholder ballot including identification of unresolved stakeholder objections and an assessment of the documentsrsquos practicality and enforceability as well as any polling information obtained during standard development

bull Regional Standards Process Manager (RSPM) - The Regional Reliability

Standards Procedure shall be administered by a NPCC staff Regional Standards Process Manager The RSPM is responsible for ensuring that the development and revision of standards is in accordance with this manual The RSPM works to ensure the integrity of the process format consistency of quality and completeness of the reliability standards The RSPM facilitates all steps in the process

bull Reliability Coordinating Committee (RCC) mdash The RCC will support the

standards development process through the assignment of NPCC Task Forces They will may also provide perform a technical advisory role in the Regional Reliability Standards development procedureprocess through comments and recommendations

bull Requester mdash A Requester is any individual or an entity (organization company government authority including the RSC etc) that submits a completed request for development revision or withdrawal of a regional standard Any person or an entity that is directly and materially affected by an existing standard or the need for a new standard may submit a request for a new standard or revision to a standard The Requester is assisted by the RSAR drafting team (if one is appointed by the RSC) or NPCC standards staff to respond to comments and to decide if and whencomplete the drafting of the RSAR is prior to it being forwarded to the RSC with a request to draft a regional standard The Requester is responsible for the RSAR assisted by the RSAR drafting team and or Regional Standards Process ManagerNPCC standards staff until such time the RSC authorizes development of the standard The Requester has the option at any time to allow the RSAR drafting team to assume full responsibility for the RSAR The Requester may choose to participate in subsequent standard drafting efforts related to the RSAR














Comment [kbc51] At what point do they do this During Open Process postings or are there other occasions

Comment [kbc52] Where did this come from It was not highlighted earlier as one of the RSCs responsibilities not in flow chart currently

17

bull Task Forces and Working Groups mdash The committees task forces and working groups within NPCC serve an active role in the standards process as follows

bull Identify the need for new or modified regional standards bull Initiate NPCC Standards actions by developing Regional Standard

Authorization Requests (RSARs) bull Develop comments (views and objections) to standards actions bull Participate in NPCC Standard drafting activities bull Provide technical oversight in response to changing industry conditions

and ERO Requirements bull Determine the need for and Cconduct Field field Teststests as required bull bull Determine the need for and perform necessary data collection and

surveys to develop the standard as required bull NPCC Compliance Committee (CC) - [Stanley to provide write up]

bull Compliance Monitoring and Enforcement Program - The NERC

compliance monitoring and enforcement program manages and enforces compliance with approved regional and NERC reliability standards The compliance program area shall provide feedback to drafting teams during the standards development process to ensure the compliance enforcement program can be practically implemented for the standards under development The compliance enforcement program may conduct field tests or data collection related to compliance elements of proposed standards and may provide assistance with field tests or data collection when requested The compliance enforcement program shares its observations regarding the need for new or modified requirements with the standards staff for use in identifying the need for new standards projects

4 4 PROCEDURE DESCRIPTION

STEPS 1 AND 2 REQUEST TO DEVELOP A NEW REGIONAL STANDARD A Requester may Rrequests to the development of

a new Rregional Reliability Sstandard

or revision of an existing standard by submitting a Regional Standard Authorization Request (RSAR) form shall be submitted to the NPCC Manager of Reliability Standards who will promptly acknowledge receipt RSPM by completing a Regional Standard Authorization Request (RSAR) which may be found on the NPCC website(see Appendix A) The RSAR is a description of the new or revised regional standard in sufficient detail to clearly define the its scope purpose and importance of the Regional Standard impacted parties or and other relevant information A ldquoneedsrdquo statement will provide the justification for the development of the standard including an assessment of the reliability and market interface impacts of implementing or not implementing the standard The RSPMManager of Reliability Standards shall maintain retain the RSAR form and make it available electronically on the NPCC website Any person or entity (ldquoRequesterrdquo) directly or materially affected by an existing standard or the need for a new or revised standard may initiate a RSAR

Comment [kbc53] Are there guidelines on the setup approval approval etc of drafting teams







Formatted Font Bold



Formatted Font Bold


Formatted Font Bold





Comment [kbc54] Vague Should this be NPCC Compliance staff


Comment [kbc55] When how How long - eg 5 business days Before posting May need an extra step





Formatted

Formatted Font Bold


Comment [kbc56] The left margin indent in this section needs to be made consistent with the rest of the document Also check for consistency in tense The procedure is for the most part written in future tense will Is this appropriate or should it be written in the present tense



Comment [kbc57] Repetition

18

The Requester will submit the RSAR to the RSPMManager of Reliability Standards electronically and the RSPMManager of Reliability Standards will acknowledge receipt of the RSAR immediately through electronic receipt The RSAR as a minimum needs shall to contain the following information in order to be qualified for consideration The NPCC RSPMManager of Reliability Standards will assist the Requester to ensure all required the following information is submitted (on the RSAR) such as in a form appearing in Appendix A

1 Proposed Title and Date of New RSAR 2 Requesterrsquos Name and Contact Information 3 Purpose of the Regional Standard 4 Description of Industry Need 5 Provide a Brief Description of the Standard 6 Identification of the Entities in the Functional Model as being responsible to

adhere to the standard 7 Necessary information to assist the drafting the team to the extent feasible to

allow them to draft the standard 8 Any existing known cross references to existing NPCC or NERC documents 89Technical background for the RSAR to properly address the need for the standard

The RSPMManager of Reliability Standards shall forward all properly completed RSARs to the RSC The RSC shall meet at established intervals to review all pending RSARs The frequency of this review process will depend on workload but in no case shall a properly completed RSAR wait for RSC action more than 60 calendar days from the date of receipt The RSC may take one of the following actions

bull Remand the RSAR back to the RSPMManager of Reliability Standards for additional work In this case the RSPMManager of Reliability Standards may request additional information or clarification for the RSAR from the Requester

bull Accept the RSAR as a candidate for a new or revised standard In this case the RSC will forward the RSAR to the RCC to assign a NPCC Task Force to provide technical support and analysis of comments for that RSAR and assist the Requester and the RSPMManager of Reliability Standards in drafting the RSARthe remaining steps of the process The RSPMManager of Reliability Standards shall within 60 calendar days of acceptance post notification of intent to develop a standard on both the NPCC website and notify the ERO to post the notification on its websites within 30 calendar days of acceptance

bull Reject the RSAR In this case the RSC will provide its determination to the Manager of Reliability Standards who will then provide a written explanation for rejection to the Requester within 30 60 calendar days of the rejection decision

STEPS 3 4 AND 5 RSC ACCEPTS RSAR AND RCC ASSIGNS TF TO DRAFT NEW OR REVISED STANDARD A RSAR that is accepted by the RSC will shall be submitted to the RCC who shall assign the development of the regional standard to a Task Force Wwithin 60 calendar days the RCC shall assign the development of the standard to a Task Force Drafting Team The RSPMManager of Reliability Standards shall oversee solicitation and recommendation of a list of additional candidates for appointment to the Drafting Tteam and shall submit the

Comment [kbc58] Not to the VP first

Comment [kbc59] No need to specify how

Comment [kbc60] of the completed RSAR

Comment [kbc61] The RSAR has been drafted already Is theis correct or does the TF assist with further refining of the RSAR This does not seem consistent with what follows in steps 3 4 and 5

Formatted Highlight

Comment [kbc62] By whom - MRS

19

list to the RSC This list shall include the Requester The RSC may select other individuals to serve in with the Task Force to drafting the Standard This The Drafting tTeam shall consist of a small group of people who collectively have the necessary technical expertise and work process skills to effectively and efficiently produce a quality standard andand the Drafting Team shall remain in place until such time as the NERC BOT adopts the regional standard Inquiries arising after a standardrsquos development shall be directed by the RSC to the tTask fForce to which the drafting of the standard was assigned The RSPMManager of Reliability Standards shall serve coordinate or assign NPCC staff personnel to assist in the drafting of the standard including compliance measures process and elements The drafting of measures and compliance administration aspects of the standard will be coordinated with the NPCC Compliance Program Staffarea When a drafting team begins its work either in refining an RSAR or in developing or revising a proposed standard the drafting team shall develop a project schedule and report its progress against that schedule to the RSC as requested through the Manager of Reliability Standards to the RSC against that schedule as requested by the RSC Once the Drafting Team has produceds a draft of the regional reliability standard VRFs VSLs variances and its associated implementation plan NPCC standards staff shall coordinates Quality Review of the draft standard consisting of technical writing legal and compliance reviews prior to submission to RSC

STEP 6 SOLICIT PUBLIC COMMENTS ON DRAFT REGIONAL STANDARD Once a draft standard has been verified by the RSC to be within the scope and purpose of the RSAR and the results of the Quality Review are deemed to be satisfactory the RSPMManager of Reliability Standards will post the draft standard for the purpose of soliciting public comments The posting of the draft standard will be linked to the RSAR for reference by its title In addition to the standard an implementation plan shall be posted to provide additional details to the public and aid in their commenting and decision process This implementation plan will be drafted and posted with draft standards upon the availability of sufficient information data or targeted survey results to determine a realistic schedule for implementation Comments on the draft standard will be accepted for a 45 calendar day period from the public notice of posting Comments will be accepted on-line using the NPCC Open Process web-based application The Manager of Reliability Standards will notify NERC to concurrently post fFinalthe draft standard and all associated documents will be concurrently posted on the ERO website for comments

STEPS 7 8 AND 9 OPEN PROCESS POSTING AND ANALYSIS OF THE COMMENTS The RSPMManager of Reliability Standards will assemble the comments on the new draft standard and distribute those comments to the Task Force acting as the standard dDrafting tTeam The Task ForceDrafting Team shall give prompt consideration to the written views and comments of all participants An effort to address all expressed submitted comments shall be madeaddressed and each commenter shall be advised of the disposition of their comments and the reasons therefore in addition toThe Manager of

Comment [kbc63] What is this intended to mean Standard development process What elements





Comment [kbc64] Who does the quality review Any criteria for this Where would the guidelines be found

Comment [kbc65] Not necessary since the Quality Review must be completed successfully before the draft standard gets to RSC

Comment [kbc66] We need more than just an effort

20

Reliability Standards shall publicly posting all of the Drafting Teamrsquos responses to stakeholder comments on the NPCC website The Task Force acting as the Standard Drafting Team shall take one of the following actions

bull Submit the draft standard for RCC endorsement as it stands along with the comments received and responses to the comments Based on the comments received the Drafting Team Task Force acting as the standard drafting team may include revisions that are not substantive A substantive change is one that directly and materially affects the application of the standard including for example changing ldquoshallrdquo to ldquoshouldrdquo changing ldquoshouldrdquo to ldquoshallrdquo adding deleting or revising requirements or adding deleting or revising measures for which compliance is mandatory

bull Make substantive revisions to the draft standard and reposts it for further open review and comment

bull Drafting Team Task Force recommends Field Test if necessary to RSC

Requester also may withdraw the request for the development of the regional standard at any time during the Regional Reliability Standard Processwithdraw the request for a standard

Upon receipt the RCC submits the proposed regional reliability standardRRS to the RSC along with its recommendation based on comments Drafting Team Task Force statements and any field test results

STEPS 10 AND 11 RSC APPROVES OF THE NEW OR REVISED STANDARD FOR POSTING If the RSC acting with consideration of any recommendations by the RCC and utilizing the composite sector voting structure as outlined in the NPCC Bylaws votes to post the draft regional standard for approval the draft standard all comments received and the responses to those comments shall be posted publicly electronically for the NPCC Members by the RSPMManager of Reliability Standards and made public throughon the NPCC Website website (wwwnpccorg) for a 30 calendar day ldquopre-ballot reviewrdquo and request for ballotingto be followed by an NPCC Member approval ballot If the RSC decides more work is needed the draft standard will be remanded back to the Drafting Teamdrafting Task Force All actions of the RCC Drafting Teams Task Forces acting as drafting teams and the Regional Standards Committee will be recorded in regular minutes of the group(s) and posted on the NPCC website Once the notice for a ballot has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued STEPS 12 13 AND 14 BALLOT OF STANDARD Upon notification of a ballot the Members of NPCCrsquos registered ballot body will cast their vote consistent with the NPCC Bylaws This ballot shall commence no sooner than 15 calendar days and no later than 30 calendar days following the notification of ballot All members of the NPCC are eligible to participate in the voting on proposed standard revisions or deletions of regional standards The ballot period will typically begin immediately following the 30 calendar day pre-ballot posting and will last at least 10 business days

Comment [kbc67] Not consistent with flowchart Box 9 in the flowchart needs to be corrected


Comment [kbc68] This statement just hangs here Perhaps it is better located in the section that describes Steps 1 and 2


Comment [kbc69] Change in tense

Comment [kbc70] Confusing Alternative text provided Is this okay

Comment [kbc71] This should either be the RCC or the Task Force to whom responsibility for drafting the regional standard was assigned

Formatted Keep with next

Formatted Indent First line 0

21

The NPCC registered ballot body comprises all entities or individuals that qualify for one of the eight NPCC stakeholder sectors and are registered with NPCC as potential ballot participants in the voting on standards Each member of the NPCC registered ballot body is eligible to vote on standards

In order for a NPCC Regional Standard to be approved

bull A quorum must be established by at least 50 of the NPCC Members of at least 60 of the Voting Sectors on the roster of Members maintained by NPCC

bull A two-thirds majority of the total weighted sector votes cast must be affirmative The number of votes cast is the sum of affirmative and negative votes excluding abstentions and non-responses Weighted sector vote will be calculated as follows o Affirmative votes cast in each sector will be divided by the sum of

affirmative and negative votes cast in that same sector to determine the fractional affirmative vote for each sector Abstentions and non-responses will not be counted for the purposes of determining the fractional affirmative vote for a sector

o The sum of the fractional affirmative votes from all sectors divided by the number of sectors voting will be used to determine if a two-thirds majority has been achieved (A sector will be considered as ldquovotingrdquo if any member of the sector in the ballot pool casts either an affirmative or a negative vote)

o A standard will be approved if the sum of fractional affirmative votes from all sectors divided by the number of voting sectors is at least 23

Ballots will be cast electronically and alternatives are as follows

bull Affirmative bull Affirmative with Comments bull Negative bull Negative with Comments bull Abstain

The RSPMManager of Reliability Standards shall post the final outcome of the ballot process If the regional standard is rejected it may be withdrawn by either the RCCRSC or the original Requester or the standard may be remanded by the RSC back to the Drafting TeamTask Force acting as the drafting team to address the issuesballotersrsquo comments In the event the proposed regional standard is withdrawn Aall comments submitted during the process will be posted and archived for consideration when redrafting the standard upon review The standard oOnce the Member ballot approvesd by ballotthe regional standard the Manager of Reliability Standards shall and a recommend final regional approval ation will be forwarded to the NPCC Board BOD for final Regional approval The Board NPCC BOD may not make substantive modifications to the standard If the Board NPCC BOD does not approve the standard for transmittal to NERC it will be remanded back to the RSC to address RCC comments

Comment [kbc72] Not consistent with flow chart This should be RSC

Comment [kbc73] Task Force to whom responsibility for drafting the standard was assigned

Comment [kbc74] From the context it seems the following actions will be take under these conditions

Comment [kbc75] The process does not address comments submitted with a ballot if the standard passes the vote As a result dissenting balloters concerns will be ignored (filed in the issues database for future reference) That is there is no equivalent of a recirculation ballot

22

If the RCC approves the regional standard is approved the Manager of Reliability Standards standard will be submitted the standard to the NERCERO Board of Trustees for approval STEPS 15 16 AND 17 IMPLEMENTATION OF THE NPCC REGIONAL STANDARD Upon approval within by the NPCC BOD the Manager of Reliability Standards shall submit the regional standard will be submitted to the NERCERO for approval(s) and filing with FERC and applicable Canadian Governmental andor Regulatory Authorities for adoption Once a reliability regional standard is adopted by the NERC BOT and submitted to and approved by either FERC andor applicable Canadian Governmental andor Regulatory Authorities andit shall made becomes effective in the applicable jurisdiction in accordance with its associated implementation plan aAll users owners planners and operators of the Bulk Power System in the NPCC geographic area of the Northeast North America are will be required to comply with the standard at this time The NERCERO Board of Trustees has established its Compliance Monitoring and Enforcement Programa separate compliance program also administered in the Northeast by NPCC to measure compliance with the reliability standards and administer sanctions as appropriate After adoption of a NPCC Rregional Sstandard the standard will be included in the forwarded to the compliance program for NERCERO compliance Compliance mMonitoring and eEnforcement Program STEP 18 WITHDRAWAL ORF REMAND OF A REGIONAL STANDARD Upon voter rejection or upon the request for the withdrawal of a proposed standard made to the the RSC CC or the requester may the RSC may elect to withdraw the standard completely or remand it back to the Task ForceDrafting Team acting as the standard drafting team for further work The Assistant Vice President-Standards will inform NERC and the industry of the actions taken

Comment [kbc76] Include VRFs VSLs Implementation Plan or do we interpret standard to include all these items

Comment [kbc77] At what time when approved or as defined in the implementation plan

Formatted Highlight

Comment [kbc78] Correct

23

RSRSubmissionto RSPM

1

RSC Review

2

Valid 3

RCC Assigns TF and also RSPM

posting Of intent to draft a

standard4

Task Force Drafts Standard

5

Open Process Postings

6

Comments7

TF Addresses Comments

Redrafts StdFTwithdrawn

8

TF Submits to RSC for Review

with all backgound and Recs

9

RSC Approves10

Post for Preballot Review

11

Standard Balloted

12

Passed13

Standard Submitted to ERO

15

Filed wFERC and Canadian Authorities

Adopted and Standard

Implemented17

RSC or Requester Withdraws

14

Yes

No

Yes

No

Yes

No

Yes

NoNo

5 FlowchartRegional Standards

Development Procedure(Open Process)

ERO Process of Approval and BOT

Approval

16

Complete Withdrawal or sent back to the

Drafting Team

18

24

6 ERO AND REGULATORY PROCESS AND APPROVALS

bull NERCERO Comment Period mdash Concurrent with regional posting of final drafts the final drafts will be forwarded to NERC for posting on the NERC website to ensure full industry awareness of the standard and expedite and coordinate all commenting NERCERO shall publicly notice and request comment on the NPCC Rregional Rreliability Sstandard and associated implementation plan allowing a minimum of 45 calendar days for comment on NERCrsquos website and actively notify all adjoining Regions Concurrent with this regional posting of final drafts the final drafts will be forwarded to NERC for posting on the NERC website to ensure full industry awareness of the standard and expedite and coordinate all commenting All comments will be responded to electronically by the Drafting Team through a posted response on the NPCC website or a link on the NERC website NPCC shall have an opportunity to resolve any objections identified in the comments and may choose to withdraw the requestposting for comment revise the NPCC Rregional Reliability Sstandard and request another posting for comment or submit the NPCC Rregional Rreliability Sstandard along with a response to any objections received for approval by NERC

bull NERCERO Approval of NPCC Regional Reliability Standards mdash

Proposed regional reliability standards shall be subject to approval by the NERCERO who shall have a process to evaluate and recommend whether a proposed non-Interconnection-wide NPCC Rregional Rreliability Sstandard has been developed in accordance with all applicable procedural requirements and whether NPCC has considered and addressed stakeholder objections NPCC BoardBOD having been notified of the results of the regional ballot concerning a NPCC Rregional Rreliability Sstandard shall vote to submit the Sstandard to the NERCERO Board BOT for approval as a NERC Rreliability Standardstandard The NERCERO Board BOT shall consider NPCCrsquos request the scope and implications of the Sstandard the recommendation for action on the Sstandard any unresolved stakeholder comments and NPCCrsquos consideration of comments and unresolved issues if any in determining whether to approve the NPCC Rregional Rreliability Sstandard as a NERC Rreliability Sstandard

bull Regulatory Authority Approval mdash An NPCC Rregional Rreliability

Sstandard that has been approved by the NERCERO board BOT shall be filed with FERC and applicable Canadian Governmental andor Regulatory Authorities for approval and shall become effective and enforceable within the US per Section 215 of the Federal Power Act only when adopted by FERC and within individual Canada provinces only when adopted by applicable Canadian Governmental andor Regulatory Authorities in accordance with any associated implementation plan The regional reliability standard once adopted will be made part of the body of NERC reliability standards and shall be mandatory and enforceable on all applicable bulk power system owners operators and users within the NPCC Region in accordance with any associated implementation plan regardless of membership status

Comment [kbc79] Consider including a list with acronyms explained for the convenience of the reader


Comment [kbc80] Should this be 16 and 17


Formatted Small caps

Comment [kbc81] Posting for pre-ballot review or comment

Comment [kbc82] anything else

Comment [kbc83] Moved above for better sequencing

Comment [kbc84] The possible outcomes have not been specified ie Accept Remand Reject What happens if NERCERO does not approve the regional standard

25

7

Appeals

bull Persons who have directly and materially affected interests and who have been or will be adversely affected by any substantive or procedural action or inaction related to the development approval revision reaffirmation or withdrawal of a regional reliability standard shall have the right to appeal This appeals process applies only to the standards process as defined in this procedure The burden of proof to show adverse effect shall be on the appellant Appeals shall be made within 30 calendar days of the date of the action purported to cause the adverse effect except appeals for inaction which may be made at any time In all cases the request for appeal must be made prior to the next step in the process The appeal must be in writing signed by an officer of the appellant

The final decisions of any appeal shall be documented in writing and made public

The appeals process provides two levels with the goal of expeditiously resolving the issue to the satisfaction of the participants

bull Level 1 Appeal

Level 1 is the required first step in the appeals process The appellant submits a complaint in writing to the RSPMManager of Reliability Standards that describes the substantive or procedural action or inaction associated with a reliability standard or the standards process The appellant describes in the complaint the actual or potential adverse impact to the appellant Assisted by any necessary staff and committee resources the RSPMManager of Reliability Standards shall prepare a written response addressed to the appellant as soon as practical but not more than 45 calendar days after receipt of the complaint If the appellant accepts the response as a satisfactory resolution of the issue both the complaint and response will be made a part of the public record associated with the standard and posted with the standard

bull Level 2 Appeal

If after the Level 1 Appeal the appellant remains unsatisfied with the resolution as indicated by the appellant in writing to the NPCC regional standards process manager the RSPMAssistant Vice-President of Standards the NPCC Assistant Vice-President of Standards shall request the BOD to convene a Level 2 Appeals Panel This panel shall consist of five members total appointed by the NPCCrsquos bBoard

In all cases Level 2 Appeals Panel members shall have no direct affiliation with the participants in the appeal

The RSPMManager of Reliability Standards shall post the complaint and other relevant materials and provide at least 30 calendar days notice of the

Comment [kbc85] Ensure this appeals process is consistent with MOUs with Canadian entities The CCEP document currently posted for ballot has been amended to achieve consistency with the Ontario appeals process contained in the MOU

Comment [kbc86] Form of the appeal Could also add language similar to the objection lower down ie contain a concise statement of

Comment [kbc87] How much time does the appellant have to write

Comment [kbc88] Is sector representation needed here if so how will this work with only 6 sectors

26

meeting of the Level 2 Appeals Panel In addition to the appellant any person that is directly and materially affected by the substantive or procedural action or inaction referenced in the complaint shall be heard by the panel The panel shall not consider any expansion of the scope of the appeal that was not presented in the Level 1 Appeal The panel may in its decision find for the appellant and remand the issue to the RSC with a statement of the issues and facts in regard to which fair and equitable action was not taken The panel may find against the appellant with a specific statement of the facts that demonstrate fair and equitable treatment of the appellant and the appellantrsquos objections The panel may not however revise approve disapprove or adopt a reliability standard The actions of the Level 2 Appeals Panel shall be publicly posted

In addition to the foregoing a procedural objection that has not been resolved may be submitted to the NPCC Board for consideration at the time the board decides whether to adopt a particular regional reliability standard The objection must be in writing signed by an officer of the objecting entity and contain a concise statement of the relief requested and a clear demonstration of the facts that justify that relief The objection must be filed no later than 30 calendar days after the announcement of the vote on the standard in question Process for Developing an Interpretation Any entity that is directly and materially affected by the reliability of the North American bulk power systems may request an interpretation of any requirement in any regional standard that has been adopted by the NERC BOT A valid interpretation request is one that requests additional clarity about one or more requirements in approved NPCC regional reliability standards but does not request approval as to how to comply with one or more requirements A valid interpretation response provides additional clarity about one or more requirements but does not expand on any requirement and does not explain how to comply with any requirement Any entity that is directly and materially affected by the reliability of the North American bulk power systems may request an interpretation of any requirement in any regional standard that has been adopted by the NERC BOT The entity requesting the interpretation shall submit a Request for Interpretation form to the NPCC Manager of Reliability Standards explaining the clarification required the specific circumstances surrounding the request and the impact of not having the interpretation provided The NPCC Manager of Reliability Standards shall work with the requester to ensure that the request for interpretation form is complete and necessary The NPCC Manager of Reliability Standards utilizing the NPCC Task Force structure shall assemble an interpretation drafting team with the relevant expertise to address the clarification As soon as practical the team shall




Comment [kbc89] May also need processes to develop a definition and retire a standard along with flowcharts


Comment [kbc90] Is this to be restricted to within the NPCC area or will any entity anywhere in North America be able to make a request



Comment [kbc92] Who makes this determination - NPCC staff


Comment [kbc93] What about other parts of the standard



Comment [kbc94] Who makes this determination


Comment [kbc95] Only requirements





Formatted Font 12 pt Not Italic Font colorAuto



Comment [kbc96] Why do we need this



Comment [kbc97] For development of a new standard the RCC assigned the standard development to a Task Force Shouldnt we adopt a similar approach here


27

develop a ldquofinal draftrdquo interpretation providing the requested clarity RCC need to get involved The NPCC Manager of Reliability Standards shall coordinate a quality review of the interpretation to assess whether the interpretation is clear and provides the requested clarity without expanding on any requirement The detailed results of this review shall be provided to the regional standard drafting team and the RSC with a recommendation on whether the documents are ready for formal posting and balloting and iIf the RSC agrees that the proposed interpretation passes this review the RSC shall authorize posting the proposed interpretation to the NPCC website The first formal comment period shall be 30- days long If the drafting team makes substantive revisions to the interpretation following the initial formal comment period then the interpretation shall undergo another quality review before it is posted for its second formal comment period The second formal comment period shall have a 45-day duration and shall start after the drafting team has posted its consideration of stakeholder comments and any conforming changes to the associated regional standard Notification of a ballot shall take place during the first 30 days of the 45-day formal comment period and the ballot of the interpretation shall take place during the last 10 days of that formal comment period The interpretation drafting team shall consider and respond to all comments submitted during the formal comment period at the same time and in the same manner as specified for addressing comments submitted with ballots All comments received and all responses shall be publicly posted to the NPCC website Stakeholders who submit comments objecting to some aspect of the interpretation shall determine if the response provided by the drafting team satisfies the objection All objectors shall be informed of the appeals process contained within this manual A ballot will be conducted utilizing quorum and approval requirements as outlined in the NPCC Bylaws If stakeholder comments indicate that there is not consensus for the interpretation and the interpretation drafting team cannot revise the interpretation without violating the basic expectations outlined above the interpretation drafting team shall notify the RSC of its conclusion and shall submit a RSAR with the proposed modification to the standard The entity that requested the interpretation shall be notified and the disposition of the interpretation shall be posted to the NPCC website If during its deliberations the interpretation drafting team identifies a reliability gap in the regional standard that is highlighted by the interpretation request the interpretation drafting team shall notify the RSC of its conclusion and shall submit a RSAR with the proposed modification to the standard at the same time it provides its proposed interpretation

Comment [kbc98] Not at this stage















Comment [kbc99] Whats the significance of this





Formatted Indent Left 075 Space After 0 pt



Formatted Highlight






Formatted Font 12 pt Highlight



28

If approved by its ballot the interpretation shall be appended to the standard and forwarded to the NPCC BOD for adoption If an interpretation drafting team proposes a modification to a regional standard as part of its work in developing an interpretation the BOD shall be notified of this proposal at the time the interpretation is submitted for adoption Following adoption by the BOD NPCC standards staff shall submit the interpretation for approval by the NERC BOT Once approved by the NERC BOT NPCC standards staff shall file the interpretation with FERC and applicable Canadian Governmental andor Regulatory Authorities for approval The standard shall become effective and enforceable within the US only when adopted by FERC and within individual Canada provinces only when adopted by applicable Canadian Governmental andor Regulatory Authorities in accordance with any associated implementation plan and the interpretation shall not become effective until approved by applicable governmental authorities The interpretation shall stand until such time as the interpretationit can be incorporated into a future revision of the regional standard or the interpretation is retired due to a future modification of the applicable requirement

Some general comments bull Complete quality check required bull ldquoProcessrdquo and ldquoprocedurerdquo are used interchangeably throughout Check for and achieve consistency bull Check for and ensure consistency in usage ldquoAn NPCCrdquo or ldquoA NPCChelliprdquo Eg see highlights on pg 4 bull Process Qn Maintenance of standards Who performs the review to determine the need to revise an existing

reliability standard ndash NPCC Staff RSC Task Force NPCC staff may trigger the review but who will do it bull Consistency check When ldquoregional reliability standardsrdquo is not used as part of a title (eg Regional Reliability

Standards Processrdquo it should be preceded by ldquoNPCCrdquo Also we must decide whether it will be capitalized or not We suggest at the first occurrence introduce a short description ie ldquohellipNPCC regional reliability standards (regional standards)helliprdquo and then use ldquoregional standardsrdquo throughout the remainder of the document

bull Consistency check Drafting Team vs Standard Drafting Team We prefer the former for consistency with NERC bull


Comment [kbc100] By whom






Formatted Font (Default) Calibri 10 pt

Formatted Indent Left 0 Hanging 013Bulleted + Level 1 + Aligned at 025 +Indent at 05

Formatted Font (Default) Calibri 10 ptEnglish (Canada)

29

30

Appendix A





Title of Proposed Standard

Request Date


Name RSAR Type (Check box for one of these selections)

Company New Standard

Telephone Revision to Existing Standard

Fax Withdrawal of Existing Standard

31

Email Urgent Action

Purpose (Describe the purpose of the proposed standard ndash what the standard will achieve in support of reliability)

Industry Need (Provide a detailed statement justifying the need for the proposed standard along with any supporting documentation)

Brief Description (Describe the proposed standard in sufficient detail to clearly define the scope in a manner that can be easily understood by others)


The Standard will Apply to the Following Functions (Check all applicable boxes)

Reliability Coordinator

The entity that is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System has the Wide Area view of the Bulk Electric System and has the operating tools processes and procedures including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations The Reliability Coordinator has the purview that is

32

broad enough to enable the calculation of Interconnection Reliability Operating Limits which may be based on the operating parameters of transmission systems beyond any Transmission Operatorrsquos vision

Balancing Authority

The responsible entity that integrates resource plans ahead of time maintains load-interchange-generation balance within a Balancing Authority Area and supports Interconnection frequency in real time

Interchange Authority

Authorizes valid and balanced Interchange Schedules

Planning Authority

The responsible entity that coordinates and integrates transmission facility and service plans resource plans and protection systems

Transmission Service Provider

The entity that administers the transmission tariff and provides Transmission Service to Transmission Customers under applicable transmission service agreements

Transmission Owner

The entity that owns and maintains transmission facilities

Transmission Operator

The entity responsible for the reliability of its ldquolocalrdquo transmission system and that operates or directs the operations of the transmission facilities

Transmission

The entity that develops a long-term (generally one year and beyond) plan for the reliability

33

Planner (adequacy) of the interconnected bulk electric transmission systems within its portion of the Planning Authority Area

Resource Planner

The entity that develops a long-term (generally one year and beyond) plan for the resource adequacy of specific loads (customer demand and energy requirements) within a Planning Authority Area

Generator Operator

The entity that operates generating unit(s) and performs the functions of supplying energy and Interconnected Operations Services

Generator Owner

Entity that owns and maintains generating units

Purchasing-Selling Entity

The entity that purchases or sells and takes title to energy capacity and Interconnected Operations Services Purchasing-Selling Entities may be affiliated or unaffiliated merchants and may or may not own generating facilities

Distribution Provider

Provides and operates the ldquowiresrdquo between the transmission system and the customer

Load-Serving Entity

Secures energy and transmission service (and related Interconnected Operations Services) to serve the electrical demand and energy requirements of its end-use customers


34

Applicable Reliability Principles (Check all boxes that apply)

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

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

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

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

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

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

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

Does the proposed Standard comply with all of the following Market Interface Principles (Select lsquoyesrsquo or lsquonorsquo from the drop-down box)

35

Recognizing that reliability is an Common Attribute of a robust North American economy

A reliability standard shall not give any market participant an unfair competitive advantageYes

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

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


Detailed Description (Provide enough detail so that an independent entity familiar with the industry could draft a standard based on this description)

Related Standards

36

Standard No

Explanation

-t


SAR ID Explanation

37

Page 1 of 5

Formatted Font color Auto

Approved by NPCC Board of Directors 9-17-08XX-XX-XXXX

Draft Scope of Work for the

Regional Standards Committee (RSC)

The NPCC Regional Standards Committee (RSC) a committee of the NPCC Board of Directors (BOD) is charged with

(a) managing the NPCC Regional Standards Ddevelopment Procedureprocess and

(b) managing the NPCC Directory and Criteria development process (bc) providing consolidated NPCC Regional review and comment to the

existing and proposed NERC Standards and participatinge in the NERC Reliability Standards Development Pprocessdure

(d) reviewing the FERC Orders Rulings and Notice of Proposed Rulemakings (NOPRs) related to reliability standards and providinge a forum for developing consensus viewpoints and submitting comments to FERC as necessary

(e) reviewing NERC Compliance Application Notices (CANs) working in coordination with the NPCC Compliance Committee (CC) and submitting comments to NERC as necessary

(e) responding to emerging standards related issues and providing support to members on an ad hoc basis for information related to NERC Alerts and Standards

(f) providing oversight and process for interpretation of Regional Standards and Criteria

(g) initiate changes to NERC and Regional Standards and Criteria after event analysis and lessons learned to reflect improvements to reliability


Decisions of the NPCC RSC RSC will be adopted under a sector based voting structure as described in the NPCC Bylaws

The RSC will coordinate its work with the Assistant Vice PresidentmdashStandards who will


of 5

be the administrator for the NPCC Regional Standards Process and the coordinator of the review and submission of comments

The RSC will be chaired by an NPCC member of staff who will be assisted by the NPCC Regional Standards Process Manager (also a member of NPCC staff) along with co-vice chairs elected by the RSC from the existing members of the committee at the time the vote is taken Co-vice chairs will serve a term of two years with an additional extension of time available through a motion and subsequent vote by the committee in accordance with the NPCC Bylaws

Members of the RSC will be elected by the NPCC Board The eight[] NPCC Sectors as outlined in the NPCC Bylaws each will be represented on the RSC

Subcommittees and ad hoc Working Groups will be formed upon request of the RSC by NPCC standards program area staff and all associated scopes or charters developed will be approved by the RSC in accordance with the most recent approved and adopted NPCC Bylaws

The NPCC RSC will work in coordination with the Assistant Vice PresidentmdashStandards who will be the administrator for the NPCC Regional Standards processDevelopment Procedure and the coordinator of the review and submission of comments to the NERC Reliability Standards


The RSC is responsible for managing the standards process for development of standards VRFs VSLs definitions variances and interpretations in accordance with the NPCC Regional Reliability Standard Process Manual The RSC is responsible for ensuring the quality of all standards related materials

A Management of the NPCC Regional Standards ProcessDevelopment Procedure

The NPCC RSC RSC will consider requests and regulatory directives for new or revised regional standards and be available for to advisement to the NPCC Board BOD on these standards or any standards related matters

The RSC may not itself modify a draft regional standard The RSC will only act on a draft standard in the event of a minor correction such as errata Substantive changes to a draft standard by the drafting team requires issuing a new notice to stakeholders regarding a vote of the modified standard

GZ and LP to work on how to incorporate language to reflect the ability to change VSLs and VRFs to continually adhere to changing FERC and NERC guidelines and requirements




Formatted Default Space After 0 pt

Page 3 of 5

The RSCrsquos disposition regarding a regional standard authorization request which will in all cases be within 60 calendar days of receipt of a completed standard request shall include(one of the following-requires RSPM revhellip)

bull ACCEPT the standard request as a candidate for development of a new standard revision of an existing standard or cancellation of an existing standard The RSC may at its discretion expand or narrow the scope of the standard request under consideration The RSC shall prioritize the development of standards in relation to other proposed standards as may be required based on the volume of requests and resources

bull REJECT the standard request If the RSC rejects a standard request a written explanation for the rejection will be delivered to the requester within 30 calendar days of the decision

bull REMAND the standard request back to the requester for additional work The Assistant Vice PresidentmdashStandards will make reasonable efforts to assist the requester in addressing the deficiencies identified by the RSC The requester may then re-submit the standard request using the process above The requester may choose to withdraw the standard request from further consideration prior to acceptance by the RSC

The NPCC Regional Standards processDevelopment Procedure responsibilities of the RSC will include

bull Overseeing quality rReview of NPCC Regional Draft Standards for such factors as completeness sufficient detail rational result format and compatibility with existing standards clarifying standard development issues not specified in this procedure Under no circumstance will the RSC change the substance of a draft standardrsquos purpose applicability or requirements

bull Due consideration to the work of the drafting team as well as the comments of stakeholders and minority objections in approving a proposed regional reliability standard to go to ballot (VSL and VRF polling)

bull Approve standards for pre-ballot posting and VSL and VRF polling under a sector based voting structure as described in the NPCC Bylaws or


Provide an oversight role in the development and maintenance of the NPCC Regional Reliability Directories

bull Provide decisions for clarifications

All regional standard related decisional making activities made by the RSC will be approved or rejected by a vote as outlined in the NPCC Bylaws as they pertain to quorum and voting rules

The RSC is responsible for managing the processes for development of NPCC Directories and Criteria The RSC is responsible for ensuring the quality of all directory and criteria

Formatted UnderlineB Management of the NPCC Directory and Criteria Process

Page 4 of 5

related materials

The RSC will be available to advise the NPCC BOD on any directory and criteria related matters

The RSC will

C NERC Reliability Standards

bull Provide NPCC review and coordinate the submission of NPCC comments to existing and developing NERC Reliability Standards when posted for NERC ldquoOpen Process Reviewrdquo

bull Provide a forum for NPCC to participate solicit and provide Regional comments as new Standard Authorization Requests (SARs) and their respective Reliability Standards are developed as part of the NERC Reliability Standards Development Procedure

bull Identify upcoming issues associated with new NERC Reliability Standards and their potential impact to the NPCC Region (ie Regional Difference) Propose solutions or guide the development of the Standards through effective and timely comments and soliciting NPCC participation on the SAR and Reliability Standards drafting teams

bull Develop and maintain a Web-Based Database for tracking and scheduling Standards development activities from a Regional perspective

bull Target a broader range of participation in the commenting process Develop databases and e-mail list servers to engage market participants and different perspectives

bull Develop an entire process for notification solicitation commenting on and revision to Standards

bull Follow up on the NERC Reliability Standards Procedure evolution and provide NPCC members with basic information (or pointers to NERC website) for a common understanding of the process

bull Coordinate activities of NPCC members on standard drafting teams

The RSC will review FERC Orders Rulings and Notice of Proposed Rulemakings (NOPRs) related to reliability standards The RSC will discuss develop comments and if necessary submit the comments to FERC The RSC will coordinate the NPCC response with that of NERC

D FERC Activities Affecting Standards

The RSC will review NERC CANs for reliability standard and compliance implications and submit comments to NERC

E NERC Compliance Application Notices (CANs)

The RSC will

bull Provide NPCC review and submit comments to draft NERC CANs bull Target a broader range of participation in the commenting process

Committee Members

Formatted Space After 18 pt Keep withnext

Formatted Underline



Formatted Highlight

Formatted Underline


Page 5 of 5

Members of the RSC will be elected by the NPCC Board The eight NPCC Sectors as outlined in the NPCC Bylaws each will be represented on the RSC

The RSC will be chaired by an NPCC member of staff who will be acting as the Regional Standards Process Manager with co-vice chairs elected by the RSC from the existing members of the committee at the time the vote is taken Co-vice chairs will serve a term of two years with a one year extension available through a motion and subsequent vote by the committee in accordance with the NPCC Bylaws

Subcommittees and ad hoc Working Groups will be formed at the behest ofupon request of the RSC by NPCC standards program area staff and all associated scopes or charters developed will be approved by the RSC in accordance with the most recent approved and adopted NPCC Bylaws

Formatted Highlight


Northeast Power Coordinating Council Inc Board of Directors Meeting Draft Minutes for Comment

February 8 2011 | 830 am NPCC Offices 1040 Avenue of the Americas 10th Floor New York New York The Chairman called to order a duly noticed meeting of the Board of Directors (Board) of Northeast Power Coordinating Council Inc (NPCC) held on February 8 2011 at 830 am A quorum was declared present during the meeting by the President and CEO Edward Schwerdt Andrianne Payson acted as Recording Secretary The meeting announcement agenda and list of attendees are attached as Exhibits A B and C respectively NPCC Antitrust Guidelines The Chairman recommended that a reading of the NPCC Antitrust Guidelines that was distributed via email with the Board agenda package and reviewed by directors upon commencement of the meeting be waived A motion to waive the reading of the NPCC Antitrust Guidelines was duly made seconded and unanimously approved Minutes The President and CEO presented for approval a draft of the minutes of the Board meeting held on December 1 2010 which incorporated all comments received Following discussion the Board agreed that the NERC Matters section of the minutes should be further revised to increase clarification A motion to approve the minutes as revised of the NPCC Board of Directors meeting held on December 1 2010 was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Presidentrsquos Report The President and CEO indicated that the Boards Strategy Meeting yesterday afternoon (February 7) and earlier this morning were worthwhile and that as part of his report to the Board he would highlight the key issues facing NPCC for 2011 and beyond bull During the process of implementing the initiative associated with the development of risk-based

standards it became apparent that there was a lack of common understanding between industry and the regulators as to (i) whether the reliability objective of risk-based standards was to prevent cascading or prevent loss of load and (ii) what constitutes an adequate level of international interconnected bulk power system reliability that appropriately balances costs and benefits to consumers The President and CEO explained that achieving consensus on these fundamental concepts including their applicability to cyber-security related reliability issues was essential to the development of standards with clear performance expectations and accountabilities He further noted that successful efforts to revise the Bulk Electric System (BES) definition and to establish consistent and technically justifiable criteria for BES definition exceptions would be critical to focusing reliability efforts in the future

bull On a procedural level it will be a challenge adapting NPCCs processes to NERCs evolving process for developing reliability standards in order to continue providing Northeast leadership The President and CEO emphasized the importance of maintaining NPCCs leadership role in the standards development process


2

bull Within the Compliance Monitoring and Enforcement Program NERC and the Regional Entities intend to introduce a more risk-based approach to compliance monitoring by considering risk and materiality in the depth and rigor of audits as well as a streamlined administrative citation process for enforcing minor violations The President and CEO explained that this approach would increase the focus on the entities and types of violations that pose the greatest risks to reliability of the bulk power system

bull In connection with the implementation of the revised Regional Delegation Agreement the Regional Entities are working with NERC to build the ERO One Enterprise model with the objectives of enhancing reliability and improving efficiency and effectiveness in working with registered entities The President and CEO noted that NERC and Regional Entity leaders attended a collaborative planning meeting in mid-January to prepare an initial draft of ERO-wide strategic goals through 2015 He explained that these draft goals would be reviewed at the February 16th NERC Member Representatives Committee meeting and that the Boards help me help you message to NERC management would be delivered

bull In connection with the development of NERC and Regional Entity 2012 Business Plans and Budgets NERCs Chief Accounting Officer recently released a preliminary draft of common business planning assumptions that would be reviewed by NERC and the Regional Entities at upcoming meetings next week The President and CEO noted that the purpose of establishing consistent planning goals and assumptions was to promote an enterprise-wide outlook for reliability related activities performed by NERC and the Regional Entities

The President and CEO indicated that he would distribute copies of his remarks to the Board shortly after meetings going forward Membership Category and Sector Designations The President and CEO stated that a Board vote would be required for the sector designations of Maine Public Service Company (General Member) and Groton Electric Light (Full Member) both in Sector 3 (Transmission Dependent Utilities Distribution Companies and Load-Serving Entities) and Penobscot Energy Recovery Company (Full Member) in Sector 4 (Generator Owners) The President and CEO also noted without the requirement for a vote a change in the designation of the Alternate Member Representative for First Wind A motion to approve the sector designations of Maine Public Service Company (General Member) in Sector 3 (Transmission Dependent Utilities Distribution Companies and Load-Serving Entities) Groton Electric Light (Full Member) in Sector 3 (Transmission Dependent Utilities Distribution Companies and Load-Serving Entities) and Penobscot Energy Recovery Company (Full Member) in Sector 4 (Generator Owners) was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Committee Membership Changes The President and CEO informed the Board that there were several changes to NPCCs operating committees

bull Reliability Coordinating Committee ndash Sector 1 (Transmission Owners) (1) Michael Paris to serve as the New York Power Authority alternate replacing Gerald LaRose who recently retired and (2) Michael Schiavone to serve as the National Grid representative replacing Dana Walters Mr Fedora also noted that the RCCs Nominating Committee was currently seeking a new co-Vice Chair for the RCC


3

bull Compliance Committee ndash Sector 1 (Transmission Owners) Michael Bilheimer to serve as the United Illuminating Company alternate

bull Regional Standards Committee ndash Sector 1 (Transmission Owners) Ben Wu to serve as the Orange and Rockland Utilities representative

bull Regional Standards Committee ndash Sector 2 (Reliability Coordinators) Donald Weaver to serve as the New Brunswick System Operator representative replacing Randy MacDonald

A motion to approve these committee changes was duly made seconded and unanimously approved by the Directors in each active Sector of the Board NPCC Committee Reports Regional Standards Committee (RSC) ndash Mr Zito presented the RSC report to the Board which included a discussion of the following (1) there is a draft ballot underway for the draft Underfrequency Load Shedding (UFLS) Regional Standard but quorum has not yet been obtained (2) the RSC is currently reviewing processes to ensure that it can react quickly and more efficiently to any new standards requirements issued by NERC and FERC and (3) the RSC is currently developing a filing for Directories for Nova Scotia and is preparing to do the same for New York State Public Service Commission In response to questions from the Board regarding NPCCrsquos review of NERCs Compliance Application Notice (CANs) postings Mr Buffamante clarified that NERCs CANs are used by compliance auditors to provide guidance while assessing an entitys compliance with reliability standards He noted that NPCC faced the challenge of ensuring that CANs do not change or expand standards requirements Mr Zito then presented the Draft 2011 RSC Work Plan which reflected significant increases in resources that would be required to (i) develop standards including 36 projects of continent-wide standards identified in the NERC Reliability Standards Development Plan 2011-2013 (ii) coordinate NPCCs participation in the revision of CIP standards and (3) assist the Compliance Committee through the development of more auditable requirements in the Phase 2 of the Directories project Board members then suggested that (i) the RSC Work Plan should include an analysis of cost effectiveness of proposed NPCC Regional Standards to convey the seriousness of this issue for NPCC (ii) the RSC reach out to NPCCs GovernmentalRegulatory Affairs Advisory Group to request they advocate for adding an analysis of cost effectiveness as part of the standards development process and (iii) the RSC recommend consolidation of NERC standards projects where appropriate A motion to approve the 2011 RSC Work Plan as revised was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Reliability Coordinating Committee (RCC) ndash Mr Fedora presented the RCC report to the Board which included information on the following (1) the approval of NPCCs long-range adequacy overview (2) endorsement of the NPCC Criteria Compliance and Enforcement Program and (3) the RCCrsquos intent to coordinate the significant increase in written requests for data from NERC The Board then discussed (i) the potential for coordinating reliability metrics data requests from NERC with information developed by the Northeast ISOs (ii) the possible development of a report reflecting the data assembled to date and (iii) the process for transitioning all NPCC criteria (A ldquoBrdquo and ldquoCrdquo Documents) into auditable requirements as appropriate in Regional Reliability Directories by the end of 2011 Mr Fedora then presented the Draft 2011 RCC Work Plan A motion to approve the 2011 RCC Work Plan was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Compliance Committee (CC) ndash Mr Kopman presented the CC report to the Board which included information on the following (1) approval of the Registered Entity Culture of Compliance Survey its initial distribution to 25 entities and the upcoming webinar on February 16 2011 to introduce the survey and answer questions (2) ongoing review of the Compliance Registry and (3) the issuance of 116 compliance

lpedowicz
Highlight
lpedowicz
Highlight


4

violation notices in 2010 (compared with 45 in 2009) and (4)the submission to NERC of mitigation plans associated with these violations (none of which have been rejected by NERC) Mr Buffamante then presented the 2011 Compliance Audit Program which reflects 21 on-site audits scheduled for 2011 11 on-site CIP audits 21 off-site CIP audits and 98 off-site audits (of which two are in progress) He informed the Board that NPCC had received and accepted 423 Technical Feasibility Exception (TFE) submissions to date and that 329 submissions had their Part B substantive assessments completed and approved He noted that NPCC is on schedule to complete assessments of the remaining submissions within a one year period Mr Penstone commended Mr Kopman and the CC for providing the Board with the CMEP metrics table which he found helpful in facilitating the Boards review and evaluation of the CCs work Mr Kopman then presented the Draft 2011 CC Work Plan which reflected the development of more comprehensive performance related to expediting the enforcement process A motion to approve the 2011 CC Work Plan was duly made seconded and unanimously approved by the Directors in each active Sector of the Board MDCC Recommendations The Board Chair reported that the Management Development and Compensation Committee (MDCC) met on January 20 2011 to discuss the 2010 Corporate Goal Attainment Report and the 2010 President and CEO Incentive Compensation Award He stated that the MDCC determined that NPCC had met its 2010 corporate goals and that NPCCs performance with respect to its Regional Entity Division and Criteria Services Division was higher than Meets Target with a composite score of 932 Board members did not have any questions for the President and CEO or the Vice President and COO in connection with the 2010 Corporate Goal Attainment Report However Mr Longhi requested that in the future a scorecard (similar to the CMEP metrics table) be prepared to show measurement of the corporate goals The President and CEO and the Vice President and COO then left the meeting The Board Chair discussed the process by which the MDCC evaluated the overall performance of the President and CEO for 2010 which included a review of the 2010 Exceptional Achievements summary prepared by the President and CEO and supporting detail for each achievement as well as the solicitation of feedback from Board members The Board Chair then distributed copies of draft resolutions with recommendations from the MDCC for Board approval A motion to approve the implementation of a 2010 Variable Incentive Program releasing incentive awards to the NPCC staff to be accrued to the salaries subaccount for 2010 for distribution in early March 2011 was duly made seconded and approved by a majority of the Directors Directors Hans Mertens and Tammy Mitchell in Sector 7 abstained from voting on this motion A motion to approve the implementation of a 2010 Variable Incentive Program releasing an incentive award to the President and CEO to be accrued to the salaries subaccount for 2010 for distribution to the President and CEO in early March 2011 was duly made seconded and approved by a majority of the Directors Directors Hans Mertens and Tammy Mitchell in Sector 7 abstained from voting on this motion The President and CEO and the Vice President and COO then returned to the meeting NPCC 2011 Corporate Goals The President and CEO presented NPCCs Proposed 2011 Corporate Goals to the Board for discussion In response to questions from the Board the President and CEO noted the following (1) the attainment of Bulk Power System revisions would be included in Goal 6a (2) following the issuance of the NERC mid-


5

year report listing certain reliability metrics discussed in Mr Fedoras RCC Report there would be a review of a few key areas for follow-up action (3) the stretch goal for Goal 6a would be revised to reflect FERC approval of a BES filing that contains key provisions that are important to NPCC (4) the corporate goals would be reviewed generally and revised as appropriate to ensure that the development of any draft document is not listed as a stretch goal and (5) each NPCC operating committee should be tasked to develop its own scorecard so the Board can assess the committee work being completed and scorecards should show separate goals relating to improving the efficiency of NPCC as an organization The Board Chair reminded Board members that comments on NPCCs Proposed 2011 Corporate Goals were due on February 18 2011 Organizational Matters CGNC Activities ndash Ms Courville briefly explained the activities of the CGNC in connection with the proposed changes to NPCCs governance structure She then asked Ms Payson to review the proposed changes to NPCCs Amended and Restated Bylaws that are intended to reflect the new governance structure Proposed Bylaw Changes Rules of Procedure for Electing Directors ndash Ms Payson discussed the proposed changes to NPCCs Amended and Restated Bylaws by reviewing the matrix summarizing the revisions to various Bylaw provisions and the Rules of Procedure for Electing Directors The Board provided several comments to the Bylaws and the Rules of Procedure which Ms Payson agreed to revise The Board discussed the proposed timeline for approval of the Amended and Restated Bylaws and agreed to send a complete package of materials to Members containing the mark-up of the Bylaws the matrix summarizing the Bylaw changes and the slide presentation providing an overview of the changes to NPCCs governance structure immediately following the next Board meeting Presentation to Members of NPCC Governance Changes ndash The President and CEO reminded Board members that a draft slide presentation to Members providing an overview of the governance structure changes was discussed during the Board Strategy Meeting on February 7 2011 Report by the Treasurer Mr Weir reported to the Board consistent with the unaudited Statement of Activities for both the Regional Entity and Criteria Services divisions for the period from January 1 2010 through December 31 2010 which had been provided to the NPCC members and Board of Directors in later January by NPCCrsquos Vice President and COO Additionally the Treasurer informed the Board that the independent auditors PricewaterhouseCoopers LLP (PwC) would likely have a draft of NPCCs audited financial statements for 2010 prepared by the end of February He reminded the Board that an unaudited Statement of Activities for 2010 for the Regional Entity Division was required by NERC as are regular quarterly reports and had been previously circulated The Treasurer indicated that NPCCs total expenditures were under budget by nearly $18 million for the year He then asked the Vice President and COO to provide an overview of NPCCs year end results for 2010 The Vice President and COO provided the Board with a breakdown of 2010 funding and comparative expenditure amounts for the total ERO Enterprise (ie NERC and the eight Regional Entities) On an enterprise basis combined funding was nearly$165 million with a variance of more than $10 million She explained that the overall variance as a percentage of total budgeted funding was under budget by 61 She noted that WECC was under budget by less than 1 NERC by 6 FRCC by 18 SPP by 22 and NPCC under by approximately 116 She further noted that total funding was largely on target with the exception of WECC where grant funding was $14 million under budget She then explained that (i) NERCs total funding was over budget by more than $800000 due to increases in fees for system operator


6

tests certificate renewals and continuing education provider fees (ii) NERC and all of the Regional Entities were under budget except for MRO which had added staff to manage processing Technical Feasibility Exceptions (iii) staff for the total ERO enterprise was approximately 98 by year end (iv) meeting expenses on an ERO wide basis were under budget by 24 compared with NPCC which was under budget by 22 (under budget variances ranged from 8 to 44 for this expense) and (v) operating expenses on an ERO wide basis were under budget by 26 or approximately $137 million compared with NPCCs under budget of 14 due mainly to lower fees and expenses for consultants professional services and legal fees She noted that NPCCs Criteria Services Division similar to the Regional Entity Division was also under budget by 42 or $463240 for 2010 The Vice President and COO informed the Directors that a NERC teleconference for its Finance and Audit Committee was being held tomorrow (February 9) where concerns would likely be expressed as to whether a Regional Entitys under spending could be viewed as underperformance of that entitys Regional Delegation Agreement (RDA) and that while expenditures were under budget NPCC would indicate that all requirements under the RDA were met during 2010 Regulatory Matters Mr Fedora provided an update of revisions to the BES definition He noted that the first meeting of the BES standard drafting team would be held on February 9-11 2011 and that he would circulate unofficial summary notes to the Board within one week after drafting team meetings NERC Matters The Board Chair noted that the meetings of the NERC Member Representatives Committee and the NERC Board of Trustees were scheduled for February 16 and 17 2011 respectively The President and CEO explained that Board policy input was requested for four items (1) ERO Enterprise Strategic Direction (2) Bulk Electric System Definition-Policy Issues and Questions (3) Priorities for Addressing Risks to Reliability and (4) Alerts and the Alerts Process Following Board discussion the President and CEO agreed to revise the draft Board Policy Input to clarify certain comments and to include recommendations for (i) any proposed implementation strategy for the BES definition to include an adequate transition period incorporating cost-effective modifications into the schedules for system modifications and (ii) the expansion of Issue 6 Integration of New Technologies to reflect a working partnership among manufacturers providers and public policy makers in order to achieve the desired reliable integration A motion to approve the draft Board Policy Input subject to revisions by the President and CEO was duly made seconded and unanimously approved by the Directors in each active Sector of the Board Administrative Matters The Board Chair reminded Board members that all Directors needed to execute the Annual Code of Conduct Implementation Agreement Other Matters Mr Haake informed the Board that he would be leaving Dynegy at the beginning of April 2011 and this would be his last Board meeting The President and CEO then informed the Board that Mr Janega had changed roles within Nova Scotia and planned to resign from the Board shortly Mr Mertens requested that Resolutions of Appreciation be prepared for both Mr Haake and Mr Janega for their efforts and contributions to the Board A motion directing the President and CEO to prepare Resolutions of Appreciation for Mr Haake and Mr Janega was duly made seconded and approved by a majority of the Directors Mr Haake abstained from voting on this motion


7

Future Meetings The President and CEO presented the schedule of Board meetings for the remainder of calendar year 2011 which was distributed via email with the Board agenda package Adjournment There being no further business the Chairman adjourned the meeting of the NPCC Board of Directors at 1240 pm Approved by Board action on _______________ 2011 Submitted by ______________________ Andrianne S Payson NPCC Secretary


8

EXHIBIT C LIST OF ATTENDEES

February 8 2011

Present Harvey J Reed Chairman Edward A Schwerdt President and CEO Jennifer Budd Mattiello Vice President and COO Christopher Weir CPA Treasurer Andrianne S Payson Esq Secretary And the following members of the Board of Directors Sector 1 (TOs) William G Longhi Orange amp Rockland Utilities

Isabelle Courville Hydro-Queacutebec TransEacutenergie (by teleconference)

Sector 2 (RCs) Peter Brandien ISO New England Inc Bruce B Campbell Independent Electricity System Operator Rick Gonzales New York Independent System Operator Inc (via proxy to President)

Sector 3 (TDUs DCs LSEs)

Douglas McCracken National Grid Michael Penstone Hydro One

Sector 4 (GOs) Glenn D Haake Dynegy Andrew Barrett Ontario Power Generation Inc Rick Janega Nova Scotia Power Inc (via proxy to President)

Sector 5 (Marketers Brokers and Aggregators)

Glen McCartney Constellation Energy Commodities Group Inc Matthew J Picardi Shell Energy NA (via proxy to President) Daniel Whyte Brookfield Power Generation

Sector 6 (Customers) ndash

Sector 7 (Regulatory) Hans Mertens Vermont Department of Public Service Tammy Mitchell NYS Department of Public Service

Sector 8 (Others) Michael Forte New York State Reliability Council LLC Guests Wes Yeoman New York Independent System Operator

Guy V Zito NPCC Assistant Vice President ndash Standards Stanley Kopman NPCC Assistant Vice President ndash Compliance Enforcement Philip Fedora NPCC Assistant Vice President ndash Reliability Services Salvatore Buffamante NPCC Assistant Vice President ndash Compliance Audits and Investigations

- 1 - LRP 312011 1027 AM


NPCC Regional Standards Committee Draft Minutes for Approval

Meeting 11-1

February 2 2011 1000 am - 500 pm (severe weather)

February 3 2011 800 am - 300 pm

NPCC Offices 1040 Avenue of the Americas

10th Floor New York New York



Items in red from Feb 2 2011 Items in green from Feb 3 2011

1 Introductions-Agenda Review-Roster a RSC membership changes Randy MacDonald (New Brunswick System Operator) moved from Sector 2 (Reliability Coordinators) to Sector 1 (Transmission Owners) Donald Weaver (New Brunswick System Operator) will replace Randy MacDonald in Sector 2 Ben Wu (Orange and Rockland Utilities Inc) will join

- 2 - LRP 312011 1027 AM

the RSC in Sector 1 Both memberships on the agenda for the Feb 8 2011 NPCC Board of Directors Meeting Wayne Sipperly (NYPA) new member (Sector 4--Generator Owner) Kal Ayoub has been promoted to Manager Reliability Standards at FERC Attendees

Name Organization Sector 1 Michael R Lombardi Northeast Utilities 1 2 Si Truc Phan Hydro-Quebec TransEnergie 2 3 Brian Gooder Ontario Power Generation Incorporated 4 4 Saurabh Saksena National Grid 3 5 Chris de Graffenried Consolidated Edison Co of New York Inc 1 6 Brian Evans-Mongeon Utility Services 5 7 Gerry Dunbar Northeast Power Coordinating Council 8 Randy MacDonald New Brunswick System Operator 1 9 Lee Pedowicz Northeast Power Coordinating Council 10 Guy Zito Northeast Power Coordinating Council 11 Bruce Metruck New York Power Authority 5 12 Wayne Sipperly New York Power Authority 4 13 Kal Ayoub (guest) FERC 14 Ben Wu (guest) Orange and Rockland Utilities Inc 1

On the Phone (Webex made available)

Name Organization Sector 1 Kurtis Chong Independent Electricity System Operator 2 2 Sylvain Clermont Hydro-Quebec TransEnergie 1 3 Ron Falsetti (guest) AESI (consultant) 4 Kathleen Goodman ISO - New England 2 5 David Kiguel Hydro One Networks Inc 1 6 Mike Garton Dominion Resources Services Inc 4 7 Diane Barney New York State Department of Public Service 7 8 Bohdan Dackow US Power Generating Company (USPG) 4 9 Greg Campoli New York Independent System Operator 2 10 Ronnie Epstein (guest) New York Power Authority 11 Donald Weaver (guest) New Brunswick System Operator 2

Guy Zito discussed the addition of Agenda Items 9c 21e 21f and 23 (Directory Development Manual)

- 3 - LRP 312011 1027 AM

2 RSC November-December 2010 Meeting Minute Approval and Antitrust Guidelines (in Meeting Materials Package) a Includes December 2 2010 joint meeting with the Compliance Committee Lee Pedowicz read the Antitrust Compliance Guidelines at the outset of the meeting David Kiguel and Randy MacDonald made changes to the Meeting Minutes Michael R Lombardi made a motion to approve the Minutes as revised Seconded by Chris de Graffenried All members present with the exception of Bruce Metruck voted to approve Bruce Metruck abstained


Package) (Refer to table at the back of Agenda) a NPCC Members on NERC Drafting Teams

Saurabh Saksena to maintain He will get updates from Carol Sedewitz

4 Review Executive Tracking Summary (in Meeting Materials Package) a Review entries

Michael R Lombardi was thanked for the work he has put into revising and maintaining the Executive Tracking Summary It is still a work in progress and it will ultimately provide ldquoone stop shoppingrdquo for RSC information There is a button on the RSC home page that takes you to the Executive Tracking Summary David Kiguel commented that it would be beneficial to access earlier versions of the Executive Tracking summary and histories of documents Saurabh Saksena discussed combining the Executive Tracking Summary with the NPCC members on NERC Drafting Teams Guy Zito expressed a desire not to do it because it would expose individualsrsquo information Guy Zito reported that on the new NPCC Website being developed (that is scheduled to be tested in March) the need for archiving will be considered

5 FERC (in Meeting Materials Package) a December 2010 Meeting Summaries

Guy Zito discussed b January 2011 Meeting Summaries

Guy Zito discussed Guy Zito proposed establishing a RSC team to develop a response to NOPRs

- 4 - LRP 312011 1027 AM

Lee Pedowicz to make a table for this item that will include the effective date the Docket Number and any other pertinent information from a posting

c Federal Register 1 Mandatory Reliability Standards for Interconnection Reliability

Operating Limits 2 System Restoration Reliability Standards 3 Revision to Electric Reliability Organization Definition of Bulk Electric

System a Request for Rehearing of the New York State Public Service

Commission of Docket No RM09-18-000 - Revision to Electric Reliability Organization Definition of Bulk Electric System

The Standards Committee had a meeting last month Brian Evans-Mongeon and Phil Fedora (NPCC) are on the Drafting Team et al are NPCC representatives on the Drafting Team The exception process is going to have to be dealt with This will depend on the comments received from the SAR posting and could result in having to dedicate resources to do studies The scope is being increased Sylvain Clermont commented that he discussed the exception process with Herb Schrayshuen A working group within NERC will be put together to look at the exception process Will also have to deal with NERC Rules and Procedures The working group will consist of stakeholders as well as NERC Staff Itrsquos not known if this will be a ldquoformalrdquo working group Brian Evans-Mongeon reported that there is a meeting next week and there is room for twenty five observers Elizabeth Crouch had sent out the notice If you signed up to be an observer yoursquod have to be physically at the meeting There were 199 pages of comments submitted for the Exception Process The Drafting Team hasnrsquot seen the comments for the Bulk Electric System definition Brian Evans-Mongeon forwarded the E-mail that contained the announcement for observers Chris de Graffenried commented that there is a jurisdiction issue that FERC and NERC donrsquot recognize Canadian Provinces are not being considered

4 System Personnel Training Reliability Standards For information only

5 Interpretation of Protection System Reliability Standard Comments on the NOPR are due Feb 25 2011

6 Version One Regional Reliability Standard for Transmission Operations Concerned with WECC

7 For information compliance filing of Proposed Violation Risk Factors and Violation Severity Levels for Available Transfer Capability Reliability Standards

8 Priorities for Addressing Risks to the Reliability of the Bulk- Power System

9 Electric Reliability Organization Interpretations of Interconnection Reliability Operations and Coordination and Transmission Operations Reliability Standards

10 Version One Regional Reliability Standards for Facilities Design Connections and Maintenance Protection and Control and Voltage

- 5 - LRP 312011 1027 AM

and Reactive Concerned with WECC


a

Project 2010-13 - Relay Loadability Order - PRC-023 PRC-023-2 Redline to last posting PRC-023-2 Redline to last approval Implementation Plan Redline to last posting VRFVSL Justification Mapping Document Announcement


Non-Binding Poll

012411 021311

b

Project 2010-11 - TPL Table 1 Order Implementation Plan TPL-001-1 Redline to last posting TPL-001-1 Redline to last approval TPL-002-1b Redline to last posting TPL-002-1b Redline to last approval TPL-003-1a Redline to last posting TPL-003-1a Redline to last approval TPL-004-1 Redline to last posting TPL-004-1 Redline to last approval Announcement

Recirculation Ballot 012611 020511

Item 6a--Kurtis Chong sent his comments to the group The meeting attendees agreed with his comments Item 6b--This Recirculation Ballot will be the last ballot Discussion ensued over the grouprsquos understanding of the footnote

- 6 - LRP 312011 1027 AM


a


COM-001-2 Redline to last posting Implementation Plan Redline to last posting COM-002-3 Redline to last posting Implementation Plan Redline to last posting IRO-001-2 Redline to last posting Implementation Plan Redline to last posting IRO-005-2 Redline to last posting Implementation Plan Redline to last posting IRO-014-2 Redline to last posting Implementation Plan Redline to last posting Comment Form (link to Word version) Announcement (initial Announcement) Announcement (latest with extension)

Comment Form

011811

030711


Join Ballot Pool 012511 022511

b

Project 2007-23 - Violation Severity Levels VSLs Redline to last Approval Comment Form (link to Word Version) Announcement

Comment Form

012011 021811

Non-Binding Poll

020911 021811

Join Ballot Pool

012011 020911

c

Project 2007-07 - Vegetation Management - FAC-003 FAC-003-2 Redline to Last Posting Implementation Plan Redline to Last Posting FAC-003-1 Comment Form (link to Word Version) Technical White Paper Redline to Last Posting

Comment Form

012711 022811


Non-Binding Poll

021811 022811

- 7 - LRP 312011 1027 AM

Announcement

Item 7a--It was noted that the ballot starts Feb 25 2011 It appears to be restricted to emergency communications Kathleen Goodman to send comments to the RSC for their consideration Some historical information offered was that a Request for Interpretation had been submitted on clarification of three part communication The RSC didnrsquot think three part communication was needed for everything The Request for Interpretation was submitted about two years ago There was a bulletin issued that stipulated that communications be three part Kathleen Goodman got no response Kathleen Goodman will be asking the Standards Committee for a status She will also send the comments that shersquoll be submitting to the IRC to the group Item 7b--Kurtis Chong discussed the IESOrsquos response to question 2 on the Comment Form Kurtis Chong to reformat the response in the form of a comment Kurtis Chong will redo the Comment Form and submit to the group Item 7c--A recommendation for the vote is needed by Feb 18 2011 Chris de Graffenried reported that Con Edisonrsquos subject matter expert suggests voting ldquoforrdquo Guy Zito told the assembled that members with overhead transmission lines should have their subject matter experts review 8 Join Ballot Pools (in Meeting Materials Package)


a

Regional Reliability Standards - PRC-006-NPCC-1 - Automatic Underfrequency Load Shedding

Comment Form (link to Word version) PRC-006-NPCC-1 Implementation Plan


b

Standards Committee Project Prioritization Tool Standards Committee Project Prioritization

Worksheet (link to Excel Spreadsheet)

Informal Comment Period 012111 021011

- 8 - LRP 312011 1027 AM

Standards Committee Reference Document for

Project Comment Form (link to Word Version) Announcement

Item 9a--This Regional Standard is going back to the Drafting Team See Item 21b1a below Kurtis Chong inquired as to why there was no quorum on the ballot for the Standard Guy Zito replied that NPCC did everything it could to get the members to vote David Kiguel brought up that NERC had ldquoticklersrdquo for balloted items Item 9b--This item was discussed earlier It will probably be approved by the NERC Board of Trustees There are a lot of open questions Guy Zito reported that this is going to be used by the Standards Committee for input to the Work Plan Brian Evans-Mongeon commented that it is still very subjective Chris de Graffenried discussed his comments Item 9c--(independent of above table)--How can the RSC be more efficient with successive ballots and all the concurrent activities taking place Guy Zito suggested the necessity of having more frequent meetings of the Executive Committee set up sub-groups within the RSC Guy Zito is trying to get a skill set of the NPCC employees to identify those that can assist with comment submissions Guy Zito is seeking observations from the participants Need to have better Task Force cooperation Better notifications would make the process more efficient and improve the cooperation of the Task Forces This should be brought to the attention of the RCC Kurtis Chong commented that when NERC makes postings on a Friday for a ten day comment period it includes two weekends It was suggested that an improvement would be to post on a Monday or a Tuesday so there is only one weekend in the comment period Guy Zito said that the Standards Committee will be informed that regional standards arenrsquot posted in the right places on the NERC Website Guy Zito reported that April 1 Stephanie Monzon (NERC) will be leaving her present standards assignment in NERC to go work for Tom Calloway (NERC) Guy Zito requested that RSC members send him their thoughts 10 Reference Documents Posted For Comment

a

- 9 - LRP 312011 1027 AM

11 Concluded Ballots (in Meeting Materials Package)

httpsstandardsnercnetBallotsaspx (clicking in the ldquoBallotrdquo column links to the Ballot Results)

Results of Ballot

RSC RecommendDate

a Project 2010-13 - Relay Loadability

Order Initial Ballot 120710 121610


No 121010

b

Project 2007-04 - Certifying System Operators - PER-003


120210 121310


Yes 91410

c Project 2010-15 - Urgent Action

Revisions to CIP-005-3

Initial Ballot and Non-

Binding Poll 120210 121110

Quorum-- 8446 Appd--

4289

No 12810

d


Successive Ballot

120110 121010

Quorum-- 8707 Appd-- 7706

No Consensus

e

Project 2007-17 - Protection System Maintenance amp Testing

Successive Ballot

121010 121910


Yes 10410

Non-binding Poll for VRFs

and VSLs 121010 121910

Quorum--7806

Supportive Opinion--5273

f

Project 2009-17 - Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State GampT


112910 12310


Yes RSC Meeting

113010

g



122010 123010


Yes 11210

h Project 2010-10 - FAC Order 729 Successive Ballot

123010 010811


Yes 10511

i Project 2010-11 - TPL Table 1 Order Initial Ballot 122710 010511

Quorum--9042 Appd--

Yes 10511

- 10 - LRP 312011 1027 AM

8333

k Project 2010-10 - FAC Order 729 Recirculation

Ballot 011411 012311


Yes 10511

Item 11k--FAC-013-2 its Implementation Plan and new definitions adopted and its

VRFs and VSLs approved approved by the NERC Board of Trustees Jan 24 2011 These documents will be filed for regulatory approval by Jan 28 2011

This added section provides good information and will be included in future agendas 12 Posted For 30-Day Pre-Ballot Review (Open Ballot Pools) Between RSC

Meetings

a


a Project 2008-06 - Cyber Security - Order 706 - CIP-002

through CIP-009 Comment

Form 120110 121010

b Project 2010-11 - TPL Table 1 Order Comment Form

111910 10511

c Project 2009-22 - Interpretation of COM-002-2 R2 by

the IRC Comment

Form 111810 121810

d Project 2007-17 - Protection System Maintenance and

Testing - PRC-005 Comment

Form 111710 121710

e Project 2010-15 - Urgent Action Revisions to CIP-005-3

- CIP-005 Comment

Form 111210 121110

f Project 2010-13 - Relay Loadability Order - PRC-023 Comment

Form 110110 121610

g Project 2010-16 - Definition of System Operator Comment Form

110310 120310

h Project 2010-10 - FAC Order 729 Comment

Form 121010 10811

i Project 2010-17 - Definition of Bulk Electric System Comment Form

121710 012111

j Resources Subcommittee White Paper on Frequency

Response Comments 1210 020111

- 11 - LRP 312011 1027 AM


a


a Project 2010-17 - Definition of Bulk Electric System Nomination

Form 121710 010411

16 NERC Meetings (in Meeting Materials Package) a ERO-RAPA b MRC and BOT Meetings 17 NERC RSG RRSWG (in Meeting Materials Package) a Update The RSG will be replacing the RRSWG The RSG will strive to achieve uniformity between regions

18 Standards Committee Report (in Meeting Materials Package) a Dec 8 2010 Meeting

At its January Meeting the Bulk Electric System Drafting Team was selected Regional Standards will be given a Quality Review--legal technical writer NERC will have a Quality Review Team for postings The review will be conducted before a ballot and the Quality Review Working Group will include a legal review It has been speculated that this review will lengthen the process

19 SCPS Meeting

Guy Zito and David Kiguel are on the SCPS Involved with the NERC processes The Standards Prioritization Project originated in this group

20 NERC Compliance Application Notices a Comments to the CAN process

Guy Zitorsquos comments from the joint meeting with the CC in December 2010 It was thought that the CAN process was closed Stan Kopman was to be the RSCrsquos conduit for comments Subsequent to the joint meeting the request for comments was made public Guy Zito to talk to Stan Kopman about how CANs will be dealt with in the future CANs 15 16 and 18 were sent out

- 12 - LRP 312011 1027 AM

David Kiguel reminded the participants to send in their responses to CANs 12 and 13 Brian Evans-Mongeon commented on a possible ldquotriagerdquo for CANs and Guy Zito stressed the need for a coordinated review of CANs This will be considered as the RSC Scope is developed

21 NPCC Regional Standards--Update (in Meeting Materials Package) a Disturbance Monitoring (PRC-002-NPCC-01)

1 VSLs approved by NPCC membership NERC Board of Trustees approved Nov 4 2010 Being prepared for FERC and Canadian entity filings



a Ten day ballot concluded on Jan 28 2011 Did not get quorum RSC to remand back to Drafting Team

c Special Protection System d Regional Reserve Sharing 1 Draft RSAR developed 2 TFCO soliciting for members


a Status of the filing Compliance Attorney looking at Phase 1 of the Directories Expect report in two weeks

23 Directory and Regional Work Plan Status Directory Number


Current Activity


Approved on 1212009

TFCP has charged CP11 with a comprehensive review of Directory 1 to include the triennial document review and an examination of the NERC TPL standards the existing NPCC planning criteria and the implementation of Phase 2 of the Directory Project which will reformat existing Directory criteria into NERC style requirements CP11 expects to present a first draft of the reformatted Directory 1 to TFCP and other Task Forces at the TFCP Meeting on Feb 9 2011 for comments CP11rsquos initial schedule called for presenting a final draft to RCC in November 2011


Approved on 102108



Approved on 71108


- 13 - LRP 312011 1027 AM


Approved on 12109



TFCO Directory5 was approved by the Full Members on December 2 2010 TFCO working to resolve outstanding reserve issues associated with Directory 5 TFCO expects to post a revised version of Directory 5 to the Open Process after their February meeting

7 (A-11)


Approved on 122707


8 (A-12)

System Restoration

Approved on 102108


9 (A-13)


Approved on 122208



Approved on 122208



Approved on 62609


X Reserve Sharing

TFCO TFCO considering draft of a new Directory on Regional Reserve Sharing which would replace C38 until a Regional Standard is developed TFCO expects to post draft of Directory X after the TFCO meeting in February

Phase 1 of the Directory Project the initial translation of criteria completed December 2010 Directory 5 was the last Directory approved RCC told TFCO to continue working on Directory 5 to resolve outstanding issues TFCO is also working on a new Directory for Regional Reserve Sharing TFCO hopes to have a draft ready for posting this spring (TFCO also has the Regional Standard on Regional Reserve Sharing) Phase 2 is underway with the reformatting of Directory 1 A Directory Development Manual is to be developed this year Developing a new NPCC Glossary of Terms is also being considered The goal is to complete Phase 2 this year and to make the Directories a real requirement

- 14 - LRP 312011 1027 AM

24 Review RFC MRO Standards Relevant to NPCC (in Meeting Materials Package)

a RFC Standards Under Development webpage httpsrsvprfirstorgdefaultaspx

b RFC Standard Voting Process (RSVP) webpage ReliabilityFirst Corporation - Reliability Standards Voting Process MOD-025-RFC-01 - Verification and Data Reporting of Generator Gross

and Net Reactive Power Capability passed its 15 day Category vote Anticipated RFC Board of Directors action to approve to approve during their March 3 2011 meeting

Standard Under


1

PRC-006-RFC-01 - Automatic Under Frequency Load Shedding Requirements

Post Comment 011211 021011

2





Adding this item to the RSC Scope to be considered A suggestion was made to make this item for information only and only when the documents listed are posted at NERC





2

- 15 - LRP 312011 1027 AM

25 Report on NERC NAESB and Regional Activities (in Meeting Materials Package)

a Report on NERC NAESB and Regional Activities 1

Lee Pedowicz to continue calling in

26 Task Force Assignments If any members want to be added to the Regional Reserve Sharing Drafting Team let Guy Zito or Lee Pedowicz know 27 Future Meetings and Other Issues (in Meeting Materials Package)

a RSC--Procedure For Handling Comments To NERC Revise procedure to better handle received comments for consensus Consider NERCrsquos latest comment issuance and resolution procedures

b NERC NPCC--Reliability Standards filed with the Nova Scotia Utility Review Board (UARB) for approval

1 Nova Scotia Information Requests for filing NPCC Criteria c Proposed Amendments To NERC Rules Of Procedure Section 300

Comments Of The Canadian Electricity Association d NERC Newsletter 1 December 2010 2 January 2011 e Link to SERC httpserccentraldesktopcomstandardhomepagedoc10275904amppgref f NERC Compliance Application Notices Guy Zito mentioned that someone needs to evaluate CANs and if it is felt

that it is needed it should be brought to the RSCrsquos attention g NERC Drafting Team vacancies

Item 27a--Lee Pedowicz is going to review and consider changing the process to more effectively capture the RSC consensus opinion Kathleen Goodman suggested incorporating a ldquodrop deadrdquo deadline to encourage timely submission of comments Other options to consider are the selective issuance to Task Forces of materials posted for comments and have a greater utilization of conference calls Suggested that when Lee Pedowicz sends out a Meeting Materials posting notification (prior to RSC Meetings) state in the transmittal that any Comment Forms will have a ldquodrop deadrdquo deadline at the RSC Meeting or at a conference call whichever is applicable Comments received late will still be issued to the RSC for informational purposes Item 27b--Informational item Item 27c--Sylvain Clermont submitted comments that specifically related to FERC Directives

- 16 - LRP 312011 1027 AM

Item 27d--Informational item Item 27e--SERC changed their home page Item 27f--discussed under Item 20 above Item 27g--For information

It was mentioned the New Brunswick automatically accepts NERC criteria Meeting adjourned 1639 on Feb 2 2011

Guy Zito opened the Feb 3 2011 session with a request for any additional items to discuss There was a discussion of NERC Successive Ballots Brian Evans-Mongeon said that regarding EOP-004 a document is being prepared to be posted for a comment period 225 pages of comments had been received Revisions made to reflect those comments Expected to go to the NERC Board of Trustees in the May-June timeframe Formal comments will be solicited in the March-April timeframe The RSC November Meeting dates have to be changed because of a conflict with the NPCC Annual and General Meetings Meeting adjourned 1221 Feb 3 2011


March 16-17 2011 Richmond Virginia

October 19-20 2011 Burlington Vermont




- 17 - LRP 312011 1027 AM


Feb 18 2011 July 15 2011 March 4 2011 August 19 2011 April 1 2011 Sept 2 2011 April 15 2011 Sept 16 2011 April 29 2011 Sept 30 2011 May 13 2011 Oct 28 2011 June 3 2011 Nov 10 2011 (Thursday) June 17 2011 Dec 16 2011 July 1 2011 Dec 30 2011


February 7-8 2011 NPCC July 28 2011 Teleconference March 15 2011 Teleconference on Bylaws September 20 2011 NPCC

May 3 2011 Teleconference October 26 2011 Teleconference June 30 2011 NPCC November 30 2011 Toronto


RCC March 3 June 1 Sept 8 Nov 29 CC Feb 15 April 13 May 16 June 14-15

July 13 August 17 Sept 21-22 Oct 19 Nov 16 Dec 13-15

TFSS Jan 20-21 TFCP Feb 9 May 11 August 17 Nov 2 TFCO Feb 24-25 April 14-15 August 11-12

Oct 6-7 TFIST TFSP Jan 18-20 March 22-24 May 24-26 July

19-21 Sept 27-29 Nov 15-17

Respectfully Submitted Guy V Zito Chair RSC Assistant Vice President-Standards Northeast Power Coordinating Council Inc

- 18 - LRP 312011 1027 AM

Northeast Power Coordinating Council Inc (NPCC) Antitrust Compliance Guidelines






competitor


- 19 - LRP 312011 1027 AM

Action Item List

Action Item

Number

Agenda Item


32 16b To discuss with Jerry Adamski how HQ because of its unique operational requirements will be addressed in standards development


RSC Meeting








Feb 17-18 2009

June 17-18 2009

August 6-7 2009



Ongoing

61 21 Notify NPCC Drafting Team members that the RSC is available for advice at any time and that they will be invited to call in with status reports


Ongoing

- 20 - LRP 312011 1027 AM

Action Item

Number

Agenda Item


Sept 24-25 2009

Nov 4-5 2009

April 21-22 2010




session April 21 2010 Ongoing There will be a joint RSCCC

Meeting in December Ralph Rufrano will be

rejoining the RSC in the capacity of

NPCC Compliance liaison Comments not to be submitted

on the CCEP June 29-30 2010


NPCC Members on NERC Drafting Teams list and provide David Kiguel with updates Lee Pedowicz sent E-mail to update individual memberrsquos status

RSC RSC Meeting

Ongoing

- 21 - LRP 312011 1027 AM

Action Item

Number

Agenda Item


August 18-19 2010



Provide update



RSC Meeting


Nov 30 2010 Dec 2 2010



RSC Meeting



Feb 2-3 2011

70 20 Talk to Stan Kopman and the CC about the process for submitting comments after Valerie Agnew (NERC) drafts CANs for their first posting Industry will have two weeks for


RSC Meeting

- 22 - LRP 312011 1027 AM

Action Item

Number

Agenda Item


comments 71 Talk to Compliance

about Reliability Standard RSAWs There should be a Compliance Committee representative on the Drafting Team

Guy Zito RSC meeting

72 Find out what other

Regions are doing regarding interpretations


73 Discuss consistency

with the RSG Guy Zito RSC

Meeting

Action Item 68--Guy Zito Lee Pedowicz Chris de Graffenried and Michael Lombardi worked on making a revision to the Regional Reliability Standards Development Procedure Guy Zito sought volunteers to review the document with the changes made Brian Gooder and Kurtis Chong volunteered and will review by mid-February The RSAW process should minimize the number of documents that when changed have to go to the Board for approval Will go in the NPCC Open Process and at NERC for approval Does the NPCC membership have to approve Action Item 69--The question was raised whether NERC Alerts should be included David Kiguel said that there are different levels of Alerts The distribution of Alerts is determined by the entity types The RSC apparently wouldnrsquot get everything Even though all Sectors are represented the representatives arenrsquot necessarily the ones receiving the Alerts Guy Zito--Eventually there will be a Regional Standard process for review of Standards and Criteria Guy Zito--Will present revised Scope ideas to the NPCC Board of Directors at their May 3 2011 Meeting (teleconference)

- 23 - LRP 312011 1027 AM

Guy Zito--NPCC organization changing from an eight sector membership to a six sector membership The Board of Directors will have a hybrid makeup The Small Customer Sector is being eliminated Guy Zito Lee Pedowicz and Michael Lombardi will work on the RSC Scope After a draft completed will distribute to the RSC Saurabh Saksena asked whether the Scope will include the review of other Regionrsquos standards RSC will stop doing it Chris de Graffenried commented that the RSC should be comparing similar regional standards Guy Zito--Presented the idea to the members of the RSC taking on more responsibility and authority

Page 1 of 3

Revised 3102011



Posted For Ballot

Industry Approved

NERC BOT Approved


1 Project 2006-01 ― System Personnel Training No PER-004-2 and PER-005-1Yes 2nd (Thru

32006)Yes 4th (Thru

71708)Yes 5th (Recirc Thru 122208) Yes (122208) Yes (040109) Yes (93009) Yes (111810) Completed

2 Project 2007-05 ― Balancing Authority Controls No NA NA NA NA NA NA NA NA


3 Project 2007-18 ― Reliability-based Control No NA NA NA NA NA NA NA NA


4 Project 2007-24 - Interpretation of TPL-002 and TPL-003 No TPL-002-0a and TPL-003-0a x xYes 2nd (Thru

7708) Yes ( 7708) Yes (73008) Yes (102408) Yes (42310) Completed

5 Project 2008-06 ― Cyber Security ― Order 706 (VRFs and VSLs) No CIP VRFs and VSLs xYes 1st (Thru



6 Project 2008-07 ― Interpretation of EOP-002-2 R63 and R71 by Brookfield Power No EOP-002-2 R63 and R71 x xYes (Recirc Thru

83109) Yes (83109)No (Remanded

21610) NA NA

21610 NERC BOT(1) Remands the proposed interpretation of EOP-002-2 Requirements R63 and R71 to the Standards Committee because the proposed interpretation adds requirements not in the standard thereby exceeding the permissible scope of an interpretation and(2) Directs the Standards Committee to initiate action to revise EOP-002-2 as appropriate NA

7 Project 2008-11 ― Interpretation of VAR-002a by ICF Consulting No VAR-002-11b x xYes (Recirc Thru


8 Project 2009-08 ― Nuclear Plant Interface Coordination No NUC-001-2Yes 1st (Thru

31809)Yes 1st (Thru


72009) Yes (72009) Yes (8509) Date Yes (12110) Completed

9 Project 2009-13 ― interpretation of CIP-006-1 by PacifiCorp No CIP-006-2c x xYes (Recirc Thru


10Project 2009-15 ― Interpretation of MOD-001-1 R2 and R8 and MOD-029-1 R5 and R6 by NYISO No MOD-001-1 R2 and R8 and MOD-029-1 R5 and R6 x x

Yes (Recirc Thru 71709) Yes (71709) Yes (11509) Yes (12209) Yes (91610) Completed

11Project 2009-16 mdash Interpretation minus CIP-007-1 R2 mdash Systems Security Management No CIP-007-2a x x

Yes (Intitial Thru 92109) Yes (92109) Yes (11509) Yes (111709) Yes (31810) Completed

12 Project 2009-18 ― Withdraw Three Midwest ISO Waivers No BAL-006-2 and INT-003-3 x xYes (Intitial Thru


13Project 2009-21 ― Cyber Security Ninety-day Response ― CIP Family of Standards No CIP-002 through CIP-009 V3



Yes (Recirc Thru 121409) Yes (121409) Yes Yes (11910) Yes (31810) Completed

14 Project 2010-12 ― Order 693 Directives NoBAL-002-1 EOP-002-3 FAC-002-1 MOD-021-1 PRC-004-2 and VAR-001-2



Yes 2nd (Recirc Thru 73110) Yes (73110) Yes (8510) Yes (9910) Yes (11011) Completed

15 Pre-2006 ― Operate Within Interconnection Reliability Operating Limits No IRO-008-1 IRO-009-1 and IRO-010-1aYes 2nd (Thru

92302)Yes 9th (Thru

42508)Yes 1st (Recirc Thru 82108) Yes (82108) Yes (101708) Yes (123109) NOPR issued 111810 - Comments were due 12411 Pending Regulatory Approval

16 Project 2006-03 ― System Restoration and Blackstart No EOP-001-2 EOP-005-2 and EOP-006-2Yes 2nd (Thru

30907)Yes 4 th (Thru

111808)Yes 5th (Recirc Thru 51809) Yes (51809) Yes (8509) Yes (123109) NOPR issued 111810 - Comments were due 12411 Pending Regulatory Approval

17 Project 2006-04 ― Backup Facilities No EOP-008-1Yes 2nd (Thru

31607)Yes 5th (Thru

3810)Yes 7th (Recirc Thru 72610) Yes (72610) Yes (85010) Yes (21111) Pending Regulatory Approval

18 Project 2006-08 ― Transmission Loading Relief No IRO-006-5 and IRO-006-East-1

Yes (For DT Nomination

11207)Yes 4th (Thru

113009)Yes 6th (Recirc Thru 83010) Yes (83010) Yes (11410) Yes (11311) Pending Regulatory Filing

19 Project 2007-27 ― Interpretation of CIP-006 R11 by SCEampG No CIP-006 R11 x xYes (Recirc Thru


20 Project 2008-06 ― Cyber Security ― Order 706 (CIP-002-4) Yes CIP-002-4 thru CIP-009-4 xYes 1st (Thru

11310)Yes Recirc Thru

123010) - passed Yes (123010) Yes (12411) Yes (21011) Pending Regulatory Approval

21 Project 2008-14 ― Cyber Security Violation Severity Levels No CIP family of standardsYes 2nd (Thru



71609) Yes (71609) Date Date Pending Regulatory Approval

22 Project 2008-15 ― Interpretation of CIP-006-1a By US Army Corps of Engineers No CIP-006-1a R4 x xYes (Recirc Thru


23 Project 2008-18 ― Interpretation of TOP-005-1 and IRO-005-1 by Manitoba Hydro No TOP-005-1 R3 and IRO-005-1 R12 x xYes (Recirc Thru

42709) Yes (42709) Yes (11509) Yes (112409) NOPR issued 121610 - Comments are due 22711 Pending Regulatory Approval

24 Project 2009-09 ― Interpretation of CIP-001-1 by Covanta No CIP-001-1 R2 x xYes (Recirc Thru


25Project 2009-10 ― Interpretation of PRC-005-1 R1 by Compliance Monitoring Processes Working Group (CMPWG) No PRC-005-1 R1 x x

Yes (Recirc Thru 8609) Yes (8609) Yes (11509) Yes (111709) NOPR issued 121610 - Comments are due 22511 Pending Regulatory Approval

26Project 2009-11 ― Interpretation of IRO-010-1 R12 and R3 by WECC Reliability Coordination Subcommittee No IRO-010-1 R12 and R3 --gt IRO-010-1a x x

Yes (Recirc Thru 6509) Yes (6509) Yes (8509) Yes (123109) NOPR issued 111810 Comments were due 12411 Pending Regulatory Approval

27 Project 2009-12 ― Interpretation of CIP-005-1 by PacifiCorp No CIP-005-1 R13 x xYes (Recirc Thru


28 Project 2009-14 ― Interpretation of TPL-002-0 R1310 by PacifiCorp No TPL-002-0 R1310 x xYes (Recirc Thru

8609) Yes (8609) Yes (11509) Yes (111709)

bull FERC NOPR [Docket RM10-6-000] - FERC reject NERCrsquos proposed interpretation and instead proposes an alternative interpretation of the provision 31810 Pending Resolution of FERC NOPR

29 Project 2009-31 ― Interpretation of TOP-001-1 R8 by FMPP No TOP-001-1 R8 x xYes 1st (Intitial Thru 31610) Yes (31610) Yes (51210) Yes (71610)

bull On 21411 NERC responded to FERCrsquos request for databull On 12811 FERC requested additional information from NERC Pending Regulatory Approval

30 Project 2010-10 ― FAC Order 729 Yes FAC-013-2Yes 1st (Thru

42910)Yes 3rd (Thru

1811)Yes 3rd (Recirc Thru 12311) Yes (12311) Yes (12411) Yes (12811) Under Development

31 Urgent Action SAR for Revision No BAL-004-1 Yes 2nd (Thru

101807)Yes 2nd (Thru

101807)Yes 1st (Recirc Thru 12407) Yes (12407) Yes (32608) Yes (31109)

FERC NOPR [Docket RM09-13-000 (March 18 2010)] - Commission proposes to remand BAL-004-1 Pending Regulatory Approval

32 Project 2007-01 ― Underfrequency Load Shedding Yes EOP-003-1 and PRC-006-1Yes 3rd (Thru

32907)Yes 3rd (Thru


33 Project 2007-04 ― Certifying System Operators No PER-003-1Yes 2nd (Thru

13108)Yes 1st (Thru

112009)Yes 3rd (Recirc Thru 121310) Yes (123110) Yes (21711) Pending Regulatory Filing

34Project 2008-09 ― Interpretation of EOP-001-0 R1 by Regional Entity Compliance Managers No EOP-001-0 R1 x x

Yes 4th (Recirc Thru 101410) Yes (101410) Yes (11410) Pending Regulatory Filing


Page 2 of 3

Revised 3102011



Posted For Ballot

Industry Approved

NERC BOT Approved



35 Project 2009-06 ― Facility Ratings No FAC-008-2Yes 2nd (Thru

9909)Yes 2nd (Thru


36Project 2009-17 ― Interpretation of PRC-004-1 and PRC-005-1 R2 by Y-W Electric and Tri-State G amp T No PRC-004-1 and PRC-005-1 x x

Yes 3rd (Recirc Thru 12310) Yes (12310) Yes (21711) Pending Regulatory Filing

37 Project 2009-27 ― Interpretation of TOP-002-2a R10 by FMPP No TOP-002-2a R10 x xYes (Recirc Thru


38 Project 2009-28 ― Interpretation of EOP-001-1 and EOP-001-2 R22 by FMPP No EOP-001-1 and EOP-001-2 x xYes (Recirc Thru


39Project 2010-09 ― Cyber Security Order 706B ― Nuclear Plant Implementation Plan No Various CIP Standards



Yes (Recirc Thru 7210) Yes (7210) Yes (8510) Pending Regulatory Filing

40 Project 2010-11 ― TPL Table 1 Order Yes TPL-002 Footnote bYes 1st (Thru

52610)Yes 3rd (Thru

1511)Yes 3rd (Recirc

Thru 2511) Yes (2511) Yes (21711)Ref FERC 31810 Order Setting Deadline for Compliance [Docket RM06-16-009] -- NERC to clarify Std TPL 002-0 Pending Regulatory Filing

41 Project 2010-13 ― Relay Loadability Order Yes PRC-023-2Yes 1st (Thru

91910)Yes 3rd (Thru

121610)

Yes 3rd (Recirculation Thru

3611) Yes (3611) Yes (31011)

On 31011 the NERC BOT approved PRC-023-2 and NERC Rules of Procedure Section 1700 - Challenges to Determinations Under Development

42 Project 2007-23 ― Violation Severity Levels No Six sets of VSLs for various standardsYes 2nd Supp (Thru 91610)

Yes 6th (Thru 21811)

Yes (Non-Binding Poll Thru 21811

NA - Non Binding Poll Only

Next StepsThe revised VSLs will be presented to the Board of Trustees for approval Under Development

43 Project 2009-20 ― Interpretation of BAL-003-0 R2 and R5 by Energy Mark Inc No BAL-003-01b x xYes (Recirc Thru

22610) Yes (22610) Under Development

44 Project 2006-02 ― Assess Transmission and Future Needs Yes TPL-001-2Yes 3rd (Thru

31607)Yes 5th (Informal

Thru 9210)Yes (Initial Thru

3110)Response to informal comments posted - Formal comments will be solicited later

On Hold - pending completion of Project 2010-11

45 Project 2006-06 ― Reliability Coordination YesCOM-001-2 COM-002-3 IRO-001-2 and IRO-014-2 (possibly IRO-003-2 - see comments)

Yes 3rd Supp (Thru 9310)

Yes 4th (Thru 3711)

Yes 1st (Intitial Thru 3711)

DT to address comments on Supplemental SAR SAR proposes to expand the scope of work under to address some directives from Order 693 that are associated with IRO-003-2 Under Development

46 Project 2007-07 ― Vegetation Management Yes FAC-003-2Yes 3rd (Thru

71707)Yes 5th (Thru

22811)Yes 4th (Initial Thru


47 Project 2007-17 ― Protection System Maintenance amp Testing Yes PRC-005-2Yes 1st (Thru

71007)

Yes 3rd (30 day formal Thru 121710)

Yes 6th (Successive Thru


48 Project 2008-10 ― Interpretation of CIP-006-1 R11 by Progress Energy No CIP-006 R11 x xYes 2nd (Initial Thru 101209)

Since at least one negative ballot included a comment the results are not final A second (or recirculation) ballot must be conducted Under Development

49Project 2009-19 ― Interpretation of BAL-002-0 R4 and R5 by NWPP Reserve Sharing Group No BAL-002-0 R4 and R5 x x

Yes (Intitial Thru 22610)

1) Pending recirculation ballot2) NERC Staff recommends that no further effort be spent on this interpretation instead allowing the BACSDT to use that energy to rewrite the standard Under Development

50 Project 2009-23 ― Interpretation of CIP-004-2 R3 by Army Corps of Engineers No CIP-004-2 x xYes 2nd (Intitial


51 Project 2009-24 ― Interpretation of EOP-005-1 R7 by FMPA No EOP-005-1 R7 x xYes 1st (Intitial Thru 11510) Balloting Deferred per Standards Committee Under Development

52 Project 2009-25 ― Interpretation of BAL-001-01 and BAL-002-0 by BPA No BAL-001-01a and BAL-002-0 x xYes 1st (Intitial Thru 11510) Pending recirculation ballot Under Development

53 Project 2009-26 ― Interpretation of CIP-004-1 by WECC No CIP-004-1 R2 R3 and R4 x xYes 1st (Intitial Thru 11910) Balloting Deferred per Standards Committee Under Development

54 Project 2009-29 ― Interpretation of TOP-002-2a R6 by FMPP No TOP-002-2a R6 x xYes 1st (Intitial Thru 22210) Pending recirculation ballot Under Development

55 Project 2009-30 ― Interpretation of PRC-001-1 R1 by WPSC No PRC-001-1 x xYes 1st (Intitial Thru 22610) Pending recirculation ballot Under Development

56 Project 2009-32 ― Interpretation of EOP-003-1 R3 and R5 by FMPP No EOP-003-1 R3 and R5 x xYes 2nd (Re-ballot


57 Project 2010-15 ― Urgent Action Revisions to CIP-005-3 No CIP-005-4Yes 1st (Thru

92710)Yes 2nd (Thru

121110)Yes 2nd (Initial Thru 121110)

Standard clasification downgraded from Urgent Action to Expedited Action Under Development

58 Project 2007-02 ― Operating Personnel Communications Protocols Yes COM-003-1 and COM-002-2Yes 2nd (Thru

5207)Yes 1st (Thru


59 Project 2007-03 ― Real-time Operations Yes TOP-001-2 TOP-002-3 and TOP-003-2Yes 2nd (Thru

90707)Yes 4th (Thru


60 Project 2007-06 ― System Protection Coordination No PRC-001-1Yes 1st (Thru

71007)Yes 1st (Thru


61 Project 2007-09 ― Generator Verification YesMOD-026-1 and PRC-024-1MOD-024-2


Yes 1st (Thru 4209)

Yes 1st (Thru 21810) Under Development

62 Project 2007-11 ― Disturbance Monitoring No PRC-002-1 and PRC-018-1Yes 1st (Thru

42007)Yes 1st (Thru


63 Project 2007-12 ― Frequency Response Yes BAL-003-1Yes 3rd (Thru

30907)Yes 1st

(Thru 3711) Posted for 30 day formal comment period Under Development

64 Project 2008-06 ― Cyber Security ― Order 706 (CIP-010-1 and CIP-011-1) Yes CIP-010-1 and CIP-011-1 xYes 1st (Informal


65 Project 2008-08 ― EOP VSL Revisions No EOP family of standardsYes 1st (Thru

51908)Yes 2nd (Thru

12309)

Subsequent to the last ballot (August 2009) of the VSLs for Projects 2007-23 and 2008-08 NERC staff reviewed the VSLs again for consistency with the FERC Guidelines The review identified some discrepancies and inconsistencies in the VSL assignments and some minor typographical errors NERC Staff along with members of the VSL drafting team proposed changes to VSLs and re-started process Under Development

66 Project 2008-12 ― Coordinate Interchange Standards No INT-004- INT-006-4 INT-009-2 INT-010-2 and INT-011-1Yes 1st (Thru

73108)Yes 1st (Thru


67 Project 2009-01 ― Disturbance and Sabotage Reporting Yes EOP-004-2Yes 1st (Thru

52109)Yes 2nd (Formal


Page 3 of 3

Revised 3102011



Posted For Ballot

Industry Approved

NERC BOT Approved



68 Project 2009-02 ― Real-time Reliability Monitoring and Analysis Capabilities Yes NewYes 2nd (Thru

21810)Yes 1st (Informal

Thru 4411) Concept White Paper posted for informal comment period Under Development

69 Project 2009-22 ― Interpretation of COM-002-2 R2 by the IRC No COM-002-2 x1st (30 day formal

thru 121810)

The team met Nov 17-18 2009 to draft a response Due to differences of opinion by the team they conducted a follow-up conference call on Dec 4 2009 NERC staff has disagreed with the interpretation and has asked that the team reconsider Under Development

70 Project 2010-07 ― Transmission Requirements at the Generator Interface NoVarious BAL CIP EOP FAC IRO MOD PER PRC TOP and VAR standards


Yes 1st(Thru 4411) Concept White Paper posted for informal comment period Project Deferred

71 Project 2010-16 ― Definition of System Operator No NERC Glossary Of TermsYes 1st (Thru

12310)Yes 1st (Thru


72 Project 2010-17 ― Definition of Bulk Electric System Yes NERC Glossary Of TermsYes 1st (Thru

12111)Yes 1st (Thru

12111)

73 Project 2010-INT-05 CIP-002-1 Requirement R3 for Duke Energy No CIP-002-1 R3 xYes 1st (Thru

10810)

74 Project 2008-01 ― Voltage and Reactive planning and control Yes VAR-001 and VAR-002Yes 2nd (Thru


75 Project 2008-02 ― Undervoltage Load Shedding No PRC-010-0 and PRC-022-1Yes 1st (Thru


76 Project 2009-03 ― Emergency Operations Yes EOP-001 EOP-002 EOP-003 and IRO-001Yes 1st (Thru


77 Project 2009-05 ― Resource Adequacy Assessments No NewYes 2nd (Thru


78 Project 2009-07 ― Reliability of Protection Systems No NewYes 1st (Thru

21809) Pending prioritization - may be postponed Under Development

79 Project 2010-08 ― Functional Model Glossary Revisions NoYes 1st (Thru


80 Project 2009-04 ― Phasor Measurement Units No Project has not started81 Project 2010-01 ― Support Personnel Training No Project has not started82 Project 2010-02 ― Connecting New Facilities to the Grid No Project has not started83 Project 2010-03 ― Modeling Data No Project has not started84 Project 2010-04 ― Demand Data No Project has not started85 Project 2010-05 ― Protection Systems No Project has not started86 Project 2010-06 ― Results-based Reliability Standards No Results-based Reliability Standards Transistion Plan Transistion Plan posted 72610

87 Project 2010-14 ― Balancing Authority Reliability-based Control No

As of July 28 2010 this project has merges Project 2007-18 - Reliability-based Controls and is now Project 2010-14 - Balancing Authority Reliability-based Control into a single project Under Development

88 Project 2010-INT-01 Interpretation of TOP-006-2 R12 and R3 for FMPP No TOP-006-2 R12 and R3 Balloting Deferred per Standards Committee On Hold89 Project 2010-INT-02 Interpretation of TOP-003-1 R2 for FMPP No TOP-003-1 R2 Balloting Deferred per Standards Committee On Hold90 Project 2010-INT-03 Interpretation of TOP-002-2a R2 R8 and R19 for FMPP No TOP-002-2a R2 R8 and R19 Balloting Deferred per Standards Committee On Hold91 Project 2010-INT-04 Interpretation of EOP-001-1 R24 for FMPP No EOP-001-1 R24 Balloting Deferred per Standards Committee On Hold

AcronymsSAR- Standards Authorization RequestRS- Reliability StandardDT- Drafting TeamSC - NERC Standards CommitteeTBD- To Be DeterminedBOT- NERC Board of Trustee

Page 1 of 1

Revised 2282011 Further details regarding the individual documents may be found at httpwwwnpccorgregStandardsUnderDevaspx

Line No Regional Standard ID Regional Reliability Standard TitleRSAR

PostedPosted for Comment

Posted For Ballot

Industry Approved

NPCC BOD Approved

NERC BOT Approved FERC Approved Comments Project Status

1 BPS-501-NPCC-01 Classification of Bulk Power System Elements (Withdrawn by RSC 80709)Yes 1st (Thru

2408) NA NA NA NA NA NA Withdrawn by RSC 80709 Withdrawn

2 PRC-002-NPCC-01 Disturbance MonitoringYes 1st (Thru

91008)Yes 3rd (Thru



3 PRC-006-NPCC-01 Automatic Underfrequency Load Shedding ProgramYes 1st (Thru

82508)Yes 2nd (Thru

7910)Yes 1st (Thru

12811)

- On 2611 NPCC RSC remanded standard back to the drafting team- Replaces Directory 12 Under frequency Load Shedding Program Requirements Under Development

4 BAL-002-NPCC-01 Regional Reserve SharingYes 1st (Thru


5 PRC-012-NPCC-01 Special Protection SystemsYes 1st (thru

81808) On Hold678910

AcronymsRSAR- Regional Standards Authorization RequestRRS- Regional Reliability StandardDT- Drafting TeamSC - NERC Standards CommitteeTBD- To Be DeterminedBOD- NPCC Board of DirectorsBOT- NERC Board of Trustee

NPCC Regional Reliability Standards Executive Tracking Summary

Page 1 of 2



Date Comments Status1 Criteria A-01 Criteria for Review and Approval of Documents2 Criteria A-03 Emergency Operation Criteria 3 Criteria A-05 Bulk Power System Protection Criteria A5 retired Directory 4 established4 Criteria A-07 Revise Critical Component Definition (Glossary of Tterms)5 Criteria A-08 NPCC Reliability Compliance and Enforcement Program 6 Criteria A-10 Classification of BPS Elements7 Criteria A-15 Disturbance Monitoring Equipment Criteria 8 Guideline B-01 NPCC Guide for the Application of Autoreclosing to the Bulk Power System9 Guideline B-12 Guidelines for On-Line Computer System Performance During Disturbances10 Guideline B-21 NPCC Guide for Analysis and Reporting of Protection System Misoperations To be retired - See C-4511 Guideline B-22 Guidelines for Implementation of the NPCC Compliance Program12 Guideline B-25 Guide to Time Suynchronization13 Guideline B-26 Guide for Application of Disturbance Recording Equipement 14 Guideline B-27 Regional Critical Asset Identification Methodology15 Guideline B-28 Guide for Generator Sequence of Events Monitoring16 Procedure C-00 Listing of NPCC Documents by Type

17 Procedure C-01NPCC Emergency Preparedness Conference Call Procedures - NPCC Security Conference Call Procedures

18 Procedure C-05 Monitoring Procedures for Emergency Operation Criteria19 Procedure C-07 Monitoring Procedures for the Guide for Rating Generating Capability

20 Procedure C-15 Procedures for Solar Magnetic Disturbances Which Affect Electric Power Systems21 Procedure C-17 Procedures for Monitoring and Reporting Critical Operating Tool Failures

22 Procedure C-21Monitoring Procedures for Conformance with Normal and Emergency Transfer Limits

23 Procedure C-25 Procedure to Collect Power System Event Data24 Procedure C-29 Procedures for System ModelingData Requirements and Facility Ratings

25 Procedure C-30Procedure for Task Force on System Protection Review of Disturbances and Protection Misoperations

26 Procedure C-32 Review Process for NPCC Reliability Compliance Enforcement Program27 Procedure C-33 Procedure for Analysis and Classification of Dynamic Control Systems28 Procedure C-36 Procedures for Communications During Emergencies29 Procedure C-39 Procedure to Collect Major Disturbance Event Data30 Procedure C-42 Procedure for Reporting and Reviewing System Disturbances31 Procedure C-43 NPCC Operational Review for the Integration of New facilities32 Procedure C-44 NPCC Regional Methodology and Procedures for Forecasting TTC and ATC

33 Procedure C-45

Procedure for Analysis and Reporting of Protection System Misoperations[CO-12 Seasonal Assessment Methodology (previously proposed but not issued - information included in the CO-12 Working Group scope instead )]

Procedure C-45 (re Protection System Misoperations) under development - will replace Guide B-21 (last updated 3111)

34 Criteria A-02 (retired) Basic Criteria for Design and Operation Of Interconnected Power Systems A2 retired Directory 1 established35 Criteria A-04 (retired) Maintenance Criteria for Bulk Power System Protection A4 retired 7112008 Directory 3 established36 Criteria A-06 (retired) Operating Reserve Criteria A6 retired 1222010 Directory 5 established37 Criteria A-11 (retired) Special Protection System Criteria Directory 7 established38 Criteria A-12 (retired) System Restoration Criteria A12 draft replaced by Directory 8 102108 Directory 8 established39 Criteria A-13 (retired) NPCC Inc Verification of Generator Gross and Net Real Power Capability A13 retired 1222200840 Criteria A-14 (retired) Verification of Generator Gross and Net Reactive Power Capability A14 retired 1222200841 Guideline B-02 (retired) Control Performance Guide B2 retired Content transferred to Directory 5 App 542 Guideline B-03 (retired) Guidelines for Inter-AREA Voltage Control B3 retired Replaced by Procedure C-4043 Guideline B-04 (retired) Guidelines for NPCC Area Transmission Reviews B4 retired Content transferred to Directory 1 AppB44 Guideline B-05 (retired) Bulk Power System Protection Guide B5 retired Content transferred to Directory 4 App A


Page 2 of 2



Date Comments Status


45 Guideline B-06 (retired) Automatic Load Shedding Employing Underfrequency Threshold Relays B6 retired Replaced by Guideline B-0746 Guideline B-07 (retired) Automatic Underfrequency Load Shedding Program B7 retired Content transferred to Directory 4 App A47 Guideline B-08 (retired) Guidelines for Area Review of Resource Adequacy B8 retired Content transferred to Directory 1 AppD48 Guideline B-09 (retired) Guide for Rating Generating Capability B9 retired Replaced by Criteria A-13 Document on July 18 200749 Guideline B-10 (retired) Guidelines for Requesting Exclusions B10 retired Content transferred to Directory 1 App E50 Guideline B-11 (retired) Special Protection System Guideline B11 retired Replaced by Criteria A-1151 Guideline B-13 (retired) Guide for Reporting System Disturbances B13 retired Replaced by Procedure C-4252 Guideline B-24 (retired) Security Guidelines for Protection System IEDS B24 retired Content transferred to Directory 4 App A53 Procedure C-03 (retired) C3 retired Replaced by Procedure C-3654 Procedure C-04 (retired) Monitoring Procedure for Guides Inter-AREA Volt Control C4 retired Content transferred to Directory 1 App G55 Procedure C-08 (retired) Monitoring Procedures for Control Performance Guide C8 retired Content transferred to Directory 5 App 556 Procedure C-09 (retired) Monitoring Procedures for Operating Reserve Criteria C9 retired Content transferred to Directory 5 App 2 57 Procedure C-10 (discontinued) C10 discontinued58 Procedure C-11 (retired) Monitoring Procedures for Interconnected System Freq Response C11 retired Content transferred to Directory 5 App 159 Procedure C-12 (retired) Procedure Shared Activation Ten Minute Reserve C12 retired Content transferred to Directory 5 Sect 58 amp App 460 Procedure C-13 (retired) Operational Planning Coordination C13 retired Content transferred to Directory 1 App F61 Procedure C-14 (retired) C14 retired Procedure C-14 was incorporated in Procedure C-1362 Procedure C-16 (retired) Procedure for Review of New or Modified BPS SPS C16 retired Content transferred to Directory 7 AppB63 Procedure C-18 (retired) Procedure for Test amp Analysis Extreme Contingencies C18 retired Content transferred to Directory 1 AppC64 Procedure C-20 (retired) Procedures During Abnormal Operating Conditions C20 retired Content transferred to Directory 5 App 365 Procedure C-22 (retired) Procedure for Reporting amp Review Proposed BPS Protection Systems C22 retired Content transferred to Directory 4 App A66 Procedure C-35 (retired) NPCC Inter-Area Power System Restoration Procedure C35 retired Incorporated within Directory 8 System Restoration67 Procedure C-37 (retired) Operating Procedures for ACE Diversity Interchange C37 retired Content transferred to Directory 5 Sect51168 Procedure C-38 (retired) Procedure for Operating Reserve Assistance Content will be transferred to new Directory 5 Reserve

69 Procedure C-40 (retired) Procedures for Inter-AREA Voltage Control C40 retiredContent transferred to Directory 1 App G amp Directory 2 App B

Acronyms

Page 1 of 1


Line No DocumentDeveloped

From Description Version Date PhaseTask Force

ReviewPosted Open

ProcessRCC

Approval

Full Membership

Ballot Comments Status

1 Directory 1 Criteria A-2 Design and Operation of the Bulk Power System 12109 (V0)Yes 1st (Thru

22811) TFCO comments due 22811 Revision Under Development2 Directory 2 Criteria A-3 Emergency Operations 1611 (V3) V3 - Errata3 Directory 3 Criteria A-4 Maintenance Criteria for Bulk Power System Protection 6309 (V1)4 Directory 4 Criteria A-5 Bulk Power System Protection Criteria 12109 (V0)

5 Directory 5 Criteria A-6 Reserve 12210 (V0)Yes 1st (Thru

xxxx)Revision sent to TFCO for review on 11111 Revision Under Development

6 Directory 67 Directory 7 Criteria A-11 Special Protection Systems 122707 (V0)8 Directory 8 Criteria A-12 System Restoration 102210 (V1)9 Directory 9 Criteria A-13 Verification of Generator Gross and Net Real Power Capability 7709 (V1)

10 Directory 10 Criteria A-14 Verification of Generator Gross and Net Reactive Power Capability 7709 (V1)11 Directory 11

12 Directory 12 Under frequency Load Shedding Program Requirements 1611 (V2) V2 - ErrataWill be replaced by Regional Standard PRC-006-NPCC-01

13 NEW Regional Reserve Sharing

RCC has directed TFCO to develop solutions to regional reserve Sharing issues contained in a new draft Directory on Regional reserve Sharing

AcronymsMC - Members CommitteeRCC - Reliability Coordinating Committee

NPCC Directory Executive Tracking Summary



February 10 2011


AGENCY HOLDING MEETING FEDERAL ENERGY REGULATORY COMMISSION DATE AND TIME February 17 2011 1000 AM PLACE Room 2C 888 First Street NE Washington DC 20426 STATUS OPEN MATTERS TO BE CONSIDERED Agenda





967TH - MEETING

REGULAR MEETING

February 17 2011


ADMINISTRATIVE A-1


A-2

AD02-7-000


ELECTRIC

E-1 ER03-563-066 Devon Power LLC

E-2 EL10-71-000 Puget Sound Energy Inc

E-3 RM11-9-000

Locational Exchanges of Wholesale Electric Power

E-4 RM11-7-000 AD10-11-000

Frequency Regulation Compensation in the Organized Wholesale Power Markets

E-5 RM10-17-000 Demand Response Compensation in Organized Wholesale Energy Markets

E-6 RM10-13-001 Credit Reforms in Organized Wholesale Electric Markets

E-7 RM08-13-001 Transmission Relay Loadability Reliability Standard

E-8 RM08-19-004 Mandatory Reliability Standards for the Calculation of Available Transfer Capability Capacity Benefit Margins Transmission Reliability Margins Total Transfer Capability and Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System

E-9 ER11-2411-000 ER11-2572-000


E-10 ER11-2455-000 ER11-2451-000


E-11 ER05-1056-005 Chehalis Power Generating LP

E-12 ER10-2869-000 Midwest Independent Transmission System Operator Inc

E-13 ER11-2427-000 ISO New England Inc

E-14 EL10-62-000 Alta Wind I LLC Alta Wind II LLC Alta Wind III LLC Alta Wind IV LLC Alta Wind V LLC Alta Wind VI LLC Alta Wind VII LLC Alta Wind VIII LLC Alta Windpower Development LLC TGP Development Company LLC

GAS

G-1 RP08-306-000 Portland Natural Gas Transmission System

G-2 IS08-390-002 SFPP LP

HYDRO

H-1 RM11-6-000 Annual Charges for Use of Government Lands



H-4 P-12532-003 P-13317-001 P-13689-001

Pine Creek Mine LLC Bishop Paiute Tribe KC LLC

CERTIFICATES

C-1 CP10-485-000

Tennessee Gas Pipeline Company

Kimberly D Bose Secretary

A free webcast of this event is available through wwwfercgov Anyone with Internet access who desires to view this event can do so by navigating to wwwfercgovrsquos Calendar of Events and locating this event in the Calendar The event will contain a link to its webcast The Capitol Connection provides technical support for the free webcasts It also offers access to this event via television in the DC area and via phone bridge for a fee If you have any questions visit wwwCapitolConnectionorg or contact Danelle Springer or David Reininger at 703-993-3100 Immediately following the conclusion of the Commission Meeting a press briefing will be held in the Commission Meeting Room Members of the public may view this briefing in the designated overflow room This statement is intended to notify the public that the press briefings that follow Commission meetings may now be viewed remotely at Commission headquarters but will not be telecast through the Capitol Connection service

From Philip A FedoraTo grpStaffCc Kenneth Lotterhos pheidrichfrcccomSubject March 17 FERC Open Meeting AgendaDate Thursday March 10 2011 75308 PMAttachments 20110310163753-CA03-17-011pdfImportance High

Of Note

E-4 RM09-18-001 Revision to ElectricReliabilityOrganization Definitionof Bulk Electric System

E-5 RM11-14-000 Analysis of HorizontalMarket Power under theFederal Power Act

E-6 RM10-16-000 System RestorationReliability Standards

E-7 RM10-10-000 Planning ResourceAdequacy AssessmentReliability Standard

E-8 RM10-15-000 Mandatory ReliabilityStandards forInterconnectionReliability OperatingLimits



March 10 2011







968TH - MEETING

REGULAR MEETING

March 17 2011


ADMINISTRATIVE A-1


A-2

AD02-7-000



Devon Power LLC

E-2 OMITTED



E-5 RM11-14-000


E-6 RM10-16-000






E-11 OMITTED

E-12 ER11-2256-000



E-14




GAS G-1 OMITTED


G-3 RP10-315-002







Line LLC

HYDRO






C-3 OMITTED

C-4 CP10-22-000






March 10 2011







968TH - MEETING

REGULAR MEETING

March 17 2011


ADMINISTRATIVE A-1


A-2

AD02-7-000



Devon Power LLC

E-2 OMITTED



E-5 RM11-14-000


E-6 RM10-16-000






E-11 OMITTED

E-12 ER11-2256-000



E-14




GAS G-1 OMITTED


G-3 RP10-315-002







Line LLC

HYDRO






C-3 OMITTED

C-4 CP10-22-000




From Philip A FedoraTo grpStaffSubject FW NERCs Draft Response to FERCs Notice of Proposed Rulemaking (NOPR) The Integration of Variable Energy ResourcesDate Friday February 25 2011 50342 PMAttachments NERC_draft_VER_NOPR_comments_02-25-11docxImportance High

Nothing like giving adequate review time hellip

By the way Monday is February 28th hellip If you have any comments please provide to me by then Thanks Phil

From Mark Lauby [mailtoMarkLaubynercnet] Sent Friday February 25 2011 446 PMSubject NERCs Draft Response to FERCs Notice of Proposed Rulemaking (NOPR) The Integration of Variable Energy Resources

DraftNERCrsquos Comments Addressing FERCrsquos Notice of Proposed Rulemaking (NOPR) Dear Planning and Operating Committee Members On December 6 2010 NERC requested comments from the Operating and Planning Committee members (see below) on its directionalresponse to FERCrsquos Notice of Proposed Rulemaking (NOPR) titled Notice of Proposed Rulemaking (NOPR) Integration of Variable EnergyResources With input from both committees as well as the Integration of Variable Generation Task Force (IVGTF) leadership team andobservers NERC has developed its final draft comments (enclosed) which must filed on March 2 2011 Please submit your incremental comments to assessmentsnercnet by noon EST on Monday March 1 2011

Chrissy VegsoNorth American Electric Reliability Corporation


6094528060 | wwwnerccomchrissyvegsonercnet

From Chrissy Vegso Sent Monday December 06 2010 1007 AMTo Chrissy VegsoSubject DRAFT POSTED NERCs Directional Topics Addressing NERCs Response to FERCs Notice of Proposed Rulemaking (NOPR)

Draft PostedNERCrsquos Directional Topics Addressing NERCrsquos Response to FERCrsquos Notice ofProposed Rulemaking (NOPR) Dear Planning and Operating Committee Members The United States Federal Energy Regulatory Commission (FERC) recently released their Notice of Proposed Rulemaking (NOPR)

UNITED STATES OF AMERICA

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

INTEGRATION OF VARIABLE)Docket No RM10-11-000

ENERGY RESOURCES)

COMMENTS OF THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION IN RESPONSE TO THE FEDERAL ENERGY REGULATORY COMMISSIONrsquoS NOVEMBER 18 2010 NOTICE OF PROPOSED RULEMAKING ON THE INTEGRATION OF VARIABLE ENERGY RESOURCES

March 2 2011

TABLE OF CONTENTS

IINTRODUCTION 1

IINOTICES AND COMMUNICATIONS 2

III BACKGROUND 2
IV DISCUSSION 3

a Inconsistency with Reliability Standards

b NERC Definition of Variable Energy Resource

c Reliability Impacts from Use of Existing or New Ancillary Services to Address Extreme Ramp Events

VCONCLUSION

I INTRODUCTION

The North American Electric Reliability Corporation (ldquoNERCrdquo) is pleased to provide these comments in response to the Federal Energy Regulatory Commissionrsquos (ldquoFERCrdquo or the ldquoCommissionrdquo) November 18 2010 Notice of Proposed Rulemaking (ldquoNOPRrdquo) on the Integration of Variable Energy Resources (ldquoVERsrdquo)[footnoteRef1] In the NOPR FERC proposes to ldquoreform the pro forma Open Access Transmission Tariff to remove unduly discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional servicesrdquo[footnoteRef2] [1 Integration of Variable Energy Resources 133 FERC para61149 (November 18 2010)(ldquoNOPRrdquo)] [2 NOPR at p 1]

NERCrsquos mission as the FERC-designated Electric Reliability Organization (ldquoEROrdquo)[footnoteRef3] is to ensure the reliability of the bulk power system in North America by in part developing and enforcing mandatory Reliability Standards NERCrsquos reliability mandate under section 215 of the Federal Power Act does not include authority to monitor and enforce market-based issues[footnoteRef4] Accordingly NERCrsquos comments herein focus on three separate areas related to the impact of the Integration of VERs on Reliability [3 See North American Electric Reliability Corporation ldquoOrder Certifying North American Electric Reliability Corporation as the Electric Reliability Organization and Ordering Compliance Filingrdquo 116 FERC para 61062 (July 20 2006)] [4 See Mandatory Reliability Standards for the Calculation of Available Transfer Capability Capacity Benefit Margins Transmission Reliability Margins Total Transfer Capability and Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System Order No 729 129 FERC para 61155 at P 109 (2009)]

II NOTICES AND COMMUNICATIONS

Notices and communications with respect to this filing may be addressed to the following

III BACKGROUND

On January 21 2010 FERC issued a Notice of Inquiry (ldquoNOIrdquo) on the Integration of Variable Energy Resources[footnoteRef5] In the NOI FERC sought comment on the extent to which barriers may exist that impede the reliable and efficient integration of VERs into the electric grid and whether reforms are needed to eliminate those barriers A 60-day comment period was set for interested parties to provide input NERC submitted comments in response to the NOI on April 12 2010[footnoteRef6] NERCrsquos comments provided responses that focused on the reliability impacts of integrating VERs into the grid and NERCrsquos ongoing efforts to address reliability considerations On November 18 2010 FERC issued its NOPR regarding the Integration of VERs in which it proposed to reform the pro forma Open Access Transmission Tariff to remove unduly discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional services[footnoteRef7] By this filing NERC provides comments in response to the NOPR [5 Integration of Variable Energy Resources 130 FERC para 61053 (January 21 2010) (ldquoNOIrdquo)] [6 See Comments Of The North American Electric Reliability Corporation In Response To The Federal Energy Regulatory Commissionrsquos January 21 2010 Notice Of Inquiry On The Integration Of Variable Energy Resources Docket No RM10-11-000 (April 12 2010)] [7 ldquoIntegration of Variable Energy Resourcesrdquo 133 FERC para 61149 (Nov 18 2010) (ldquoNOPRrdquo)]

IV DISCUSSION

In formulating its response to the NOPR NERC sought input from industry stakeholders the NERC Operating Committee NERC Planning Committee and the Integration of Variable Resources Task Force (ldquoIVGTFrdquo) To this end NERC posted to its website a letter addressed to its Planning and Operating Committees titled NERCrsquos Directional Topics Addressing NERCrsquos Response to FERCrsquos Notice of Proposed Rulemaking on Integration of Variable Energy Resources[footnoteRef8] In this posting NERC provided reliability considerations and sought input from the committee members on the three separate areas relating to the integration of VERs discussed below [8 httpwwwnerccomfilezpchtml ]

a Inconsistency with NERC Reliability Standards

In the NOPR the Commission proposed ldquoto amend sections 138 and 146 of the pro forma OATT to provide transmission customers the option to schedule transmission service on an intra-hour basis at intervals of 15 minutesrdquo[footnoteRef9] Noting that the proposed 15-minute interval was ldquoconsistent with the ideal time increments ( ie 5 to 15 minutes) recommended by NERCrdquo the Commission requested comment on whether there was any inconsistency among relevant NERC Reliability Standards and the proposed intra-hour scheduling tariff reform [9 NOPR at P 37]

In response to the Commissionrsquos request for comment NERC worked with industry stakeholders to perform a preliminary review of its Reliability Standards NERC has not identified any insurmountable hurdles that would prevent the industry from providing intra-hour scheduling flexibility NERC notes that certain entities currently offer various forms of scheduling on a 15-minutes basis and to date NERC is not aware of this causing any conflicts with NERCrsquos Reliability Standards
Yet NERC acknowledges that making a 15-minute scheduling interval more routine including (critically) for inter-Balancing Area (BA) transactions would likely require review and refinements to several existing Reliability Standards[footnoteRef10] In particular there would likely be a need for changes to NERCrsquos Interchange Scheduling and Maintenance Coordination (INT) Reliability Standards which were largely written based on the assumption that many schedules will be on an hourly basis To the extent that this assumption has resulted in wording that is consistent with an hourly regime interpretations or modifications to the INT Reliability Standards would likely be required While it is expected that only minor wording changes to affected standards may be necessary adopting interconnection-wide intra-hour scheduling could have a substantial impact on practices and tools used by transmission operators to maintain reliable operations Time and attention to the details (regarding impacts and changes to Reliability Standards practices and tools) would be required but a transition to more widespread use of intra-hour scheduling flexibility is achievable in a reasonable time frame [10 See eg NERC Reliability Standards BAL-005 R121 (Automatic Generation Control) BAL-006 R1 (Inadvertent Interchange) EOP-008 (Plans for Loss of Control Center Functionality) INT-001 R11 (Interchange Information) INT-004-2 (Dynamic Interchange Transaction Modifications) INT-005-003 (Interchange Authority Distributes Arranged Interchange) INT-006-3 (Response to Interchange Authority) INT-008 R1 (Interchange Authority Distributes Status)]

However it should be noted that all creation and modification of Reliability Standards must be considered as part of the NERC Reliability Standards Committee prioritization process This prioritization process considers the regulatory reliability and logistical issues associated with projects to create or modify NERC standards and helps determine the manner in which industry resources and NERC staff are deployed to create or modify Reliability Standards Additionally such changes must be developed in accordance with the steps outlined in the NERC Standards Process Manual which ensures an open and inclusive process through adherence to the standards development principles of the American National Standards Institute

In the NOPR the Commission proposed to ldquoallow all transmission customers the option of submitting intra-hour schedules up to 15 minutes before the scheduling intervalrdquo[footnoteRef11] NERC notes that the INT Reliability Standards have been written so that nearly all schedules are received at least 20 minutes ahead of the block-schedule start This 20-minute period was set to provide the operator sufficient time to evaluate approve and implement the schedule request For example if an Eastern Interconnection schedule request is submitted at 0040 for a schedule that starts at 0100 then industry actions may include [11 NOPR at 41]

middot communication time will be required as the request is transmitted received and processed

middot the entities reviewing the request will require sufficient time to evaluate the request

middot communication time will be required to verify that all entities have agreed to implement the requested schedule and coordinate that agreement between all entities and

middot entities will need time to input the request into their scheduling systems

When combined the required time is at least 15 minutes (0055) to perform these tasks with the remaining time allowing for the initiation of the ramp which in the Eastern Interconnection is based on the standard ramp of 10 minutes that straddles across the block-schedule start ( eg begin ramping at 0055 and complete ramping at 0105) Changes that impact this timing will need to be accounted for in modifications to the associated INT Reliability Standards ( ie INT-005 and INT-008) and will result in significant changes in the way in which operators currently process such requests As a result of this fairly tight advance notice time frame for processing schedule changes any change to the existing 20-minute prior notice evaluation period for schedules should be undertaken with caution

The Commission also requested comments regarding any changes that might be necessary in hardware software or personnel As indicated above NERC is informed that transmission providers offering and executing on 15 minute scheduling would require changes (some substantial) to existing tools and processes used to perform scheduling and curtailment activities For example the Interchange Distribution Calculator a tool which is used in the Eastern Interconnection to manage congestion generally operates on an hourly basis as does the Western Interconnections WebSAS tool In addition wide-spread intra-hour scheduling may require system operators to adopt increasingly automated processes as significant aspects of existing processes ( ie check out) are often performed manually The need to account for shorter-term schedules combined with the potential increase in volume of transactions processed would in some instances require changes to both hardware and software NERC believes such analysis would need to be performed subsequent to the issuance of a Final Rule (so the requirements are known) but before implementation becomes mandatory

While NERC does not have personnel that would be directly impacted by the proposed change NERC believes that entities that review and implement schedule requests would likely see their personnel needs increase Such entities would also likely see increased demands on their software and hardware associated with processing schedule requests

b NERC Definition of Variable Energy Resource

In the NOPR FERC proposed to define a VER as ldquoenergy source that (1) is renewable (2) cannot be stored by the facility owner or operator and (3) has variability that is beyond the control of the facility owner or operatorrdquo[footnoteRef12] Noting that this definition is consistent with NERCrsquos characterization of variable generation the Commission sought comment on the proposed VER definition NERC supports the VER definition proposed by the Commission and believes it is sufficient [12 NOPR at P 64 (citing NERC Accommodating High Levels of Variable Generation at 13-14 (2009) available at httpwwwnerccomfilesIVGTF_Report_041609pdf)]

c Reliability Impacts from Use of Existing or New Ancillary Services to Address Extreme Ramp Events

In the NOPR the Commission requested comments ldquoon the extent to which some additional type of contingency reserve service (beyond the services provided under Schedule 5 and 6 of the pro forma OATT) would ensure that VERs are integrated into the interstate transmission system in a non-discriminatory manner while remaining consistent with NERC Reliability Standardsrdquo[footnoteRef13] [13 NOPR at P 100]

Large wind ramping events have characteristics that are both similar to and different than conventional generator contingency events They are similar in that the large events are large and infrequent They differ in that wind ramps are much slower than instantaneous contingency events and the extreme wind ramps may be possible to forecast Figure 1 below shows a large (1500 MW) wind ramp event that occurred in February 2007 in the Electric Reliability Council of Texas (ldquoERCOTrdquo) region While this event is large and can present a serious operational challenge it is a rare event occurring about once a year and it emerges slowly compared with a conventional generation contingency which happens essentially instantaneously

Figure 1 ERCOT 2242007 wind event

The use of contingency reserves is similar to what is used to address large infrequent wind ramps because contingency reserves are seldom deployed Typically contingency reserves are split between spinning and non-spinning For large ramps lasting several hours the ramp duration make it difficult to include wind ramps as actual contingencies Resource and Demand Balancing (BAL) Reliability Standard BAL-002 (Disturbance Control Performance) requires ACE to be restored 15 minutes following the disturbance (R4) and the contingency reserves to be restored within 105 minutes (90 minutes after the 15 minute disturbance recovery period ndash R6) Both of these requirements can be problematic for wind ramps since they can be longer than the disturbance recovery period as well as the reserve restoration period System operators typically restore reserves much faster (within approximately ten minutes following the disturbance recovery period) Therefore including two hour wind ramps as contingencies would also be problematic

A further issue with a large long ramp is the point at which the event can be identified For example during the ERCOT event in the Figure 1 above a full 20 minutes into the event it may not be clear to the operator whether the wind power will continue declining or whether the ramp is (nearly) over This highlights the importance of an accurate wind forecast so that wind generators can schedule a reasonable forecast of their expected output

Still it may be appropriate to use contingency reserves in response to a portion of a wind ramp Shared contingency reserves could be used to initiate the response allowing time for alternate supply (or load reduction) to be implemented The frequency of ramp events would need to be studied to determine which ramps are compatible with contingency reserve use The industry should consider developing rules governing reserve deployment and restoration similar to those that currently address conventional contingencies would also need to be developed

Some entities are considering rules that will allow contingency reserves to be deployed to help manage large infrequent wind ramping events NERC believes that the industry should consider how best to deal with this incremental risk Specifically NERC believes that further analysis of how wind ramps can be recovered using contingency reserves should be undertaken as well as consideration of how wind generation can minimize the impacts of wind ramps through improved forecasting and market tools products and requirements The predictability duration magnitude and ramp rate of an event are all important factors that are used in determining how reserves for these events should be held

If Balancing Authorities can predict an occurring event and to some degree know the duration magnitude and ramp rate of a future event they can use that information to ensure that the correct reserve is ready to be deployed This type of analysis could potentially be done with historic data that demonstrates the characteristics of the wind regime of the particular balancing area (as shown in the Figure 1)

With improved forecasting systems real-time forecast information should also be used to assist in determining what reserve requirements to hold for such events

V CONCLUSION

NERC is pleased to provide these comments in response to the Commissionrsquos NOPR and looks forward to working with the Commission to ensure the successful integration of VERs while maintaining the reliability of the bulk power system

Respectfully submitted

6

CERTIFICATE OF SERVICE

I hereby certify that I have served a copy of the foregoing document upon all parties listed on the official service list compiled by the Secretary in this proceeding

Dated at Washington DC this 2nd day of March 2011

s Willie L Phillips

Willie L Phillips


image1png

Integration of Variable Energy Resources NERC has posted a draft letter to the Planning and Operating Committees identifying threeareas of FERCrsquos Notice to which it intends to provide comments (httpwwwnerccomfilezpchtml) In this letter NERC providesdirectional reliability considerations and seeks input from the Planning and Operating Committee members

In addition to the Operating and Planning Committees NERC plans to seek detailed input from the Integration of the Variable ResourcesTask Force (IVGTF) Before filing NERC staffrsquos draft comments will be sent for your final consideration Please submit your comments to assessmentsnercnet by Monday December 20 2010

Chrissy VegsoNorth American Electric Reliability Corporation


6094528060 | wwwnerccomchrissyvegsonercnet

---You are currently subscribed to pc_plus as pfedoranpccorgTo unsubscribe send a blank email to leave-1249359-159822efb8cca4334e86463d80bb177caa7b75listservnerccom



INTEGRATION OF VARIABLE ) Docket No RM10-11-000 ENERGY RESOURCES )

COMMENTS OF THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION IN RESPONSE TO THE FEDERAL ENERGY REGULATORY

COMMISSIONrsquoS NOVEMBER 18 2010 NOTICE OF PROPOSED RULEMAKING ON THE INTEGRATION OF VARIABLE ENERGY RESOURCES

Gerald W Cauley President and Chief Executive Officer David N Cook Sr Vice President and General Counsel North American Electric Reliability

Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet



March 2 2011

TABLE OF CONTENTS

I INTRODUCTION 1

II NOTICES AND COMMUNICATIONS 2

III BACKGROUND 2

IV DISCUSSION 3

a Inconsistency with Reliability Standards



V CONCLUSION

1

I

The North American Electric Reliability Corporation (ldquoNERCrdquo) is pleased to provide

these comments in response to the Federal Energy Regulatory Commissionrsquos (ldquoFERCrdquo or the

ldquoCommissionrdquo) November 18 2010 Notice of Proposed Rulemaking (ldquoNOPRrdquo) on the

Integration of Variable Energy Resources (ldquoVERsrdquo)

INTRODUCTION

1 In the NOPR FERC proposes to ldquoreform

the pro forma Open Access Transmission Tariff to remove unduly discriminatory practices and

to ensure just and reasonable rates for Commission-jurisdictional servicesrdquo2

NERCrsquos mission as the FERC-designated Electric Reliability Organization (ldquoEROrdquo)

3 is

to ensure the reliability of the bulk power system in North America by in part developing and

enforcing mandatory Reliability Standards NERCrsquos reliability mandate under section 215 of the

Federal Power Act does not include authority to monitor and enforce market-based issues4

Accordingly NERCrsquos comments herein focus on three separate areas related to the impact of the

Integration of VERs on Reliability

1 Integration of Variable Energy Resources 133 FERC para61149 (November 18 2010)(ldquoNOPRrdquo) 2 NOPR at p 1 3 See North American Electric Reliability Corporation ldquoOrder Certifying North American Electric Reliability Corporation as the Electric Reliability Organization and Ordering Compliance Filingrdquo 116 FERC para 61062 (July 20 2006) 4 See Mandatory Reliability Standards for the Calculation of Available Transfer Capability Capacity Benefit Margins Transmission Reliability Margins Total Transfer Capability and Existing Transmission Commitments and Mandatory Reliability Standards for the Bulk-Power System Order No 729 129 FERC para 61155 at P 109 (2009)

2

II


following


Gerald W Cauley President and Chief Executive Officer David N Cook Sr Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet Persons to be included on FERCrsquos service list are indicated with an asterisk NERC requests waiver of FERCrsquos rules and regulations to permit the inclusion of more than two people on the service list



III BACKGROUND

On January 21 2010 FERC issued a Notice of Inquiry (ldquoNOIrdquo) on the Integration of

Variable Energy Resources5

5 Integration of Variable Energy Resources 130 FERC para 61053 (January 21 2010) (ldquoNOIrdquo)

In the NOI FERC sought comment on the extent to which barriers

may exist that impede the reliable and efficient integration of VERs into the electric grid and

whether reforms are needed to eliminate those barriers A 60-day comment period was set for

interested parties to provide input NERC submitted comments in response to the NOI on April

3

12 20106 NERCrsquos comments provided responses that focused on the reliability impacts of

integrating VERs into the grid and NERCrsquos ongoing efforts to address reliability considerations

On November 18 2010 FERC issued its NOPR regarding the Integration of VERs in which it

proposed to reform the pro forma Open Access Transmission Tariff to remove unduly

discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional

services7

By this filing NERC provides comments in response to the NOPR

IV

In formulating its response to the NOPR NERC sought input from industry stakeholders

the NERC Operating Committee NERC Planning Committee and the Integration of Variable

Resources Task Force (ldquoIVGTFrdquo) To this end NERC posted to its website a letter addressed to

its Planning and Operating Committees titled NERCrsquos Directional Topics Addressing NERCrsquos

Response to FERCrsquos Notice of Proposed Rulemaking on Integration of Variable Energy

Resources

DISCUSSION

8

a Inconsistency with NERC Reliability Standards

In this posting NERC provided reliability considerations and sought input from the

committee members on the three separate areas relating to the integration of VERs discussed

below

In the NOPR the Commission proposed ldquoto amend sections 138 and 146 of the pro

forma OATT to provide transmission customers the option to schedule transmission service on

6 See Comments Of The North American Electric Reliability Corporation In Response To The Federal Energy Regulatory Commissionrsquos January 21 2010 Notice Of Inquiry On The Integration Of Variable Energy Resources Docket No RM10-11-000 (April 12 2010) 7 ldquoIntegration of Variable Energy Resourcesrdquo 133 FERC para 61149 (Nov 18 2010) (ldquoNOPRrdquo) 8 httpwwwnerccomfilezpchtml

4

an intra-hour basis at intervals of 15 minutesrdquo9

In response to the Commissionrsquos request for comment NERC worked with industry

stakeholders to perform a preliminary review of its Reliability Standards NERC has not

identified any insurmountable hurdles that would prevent the industry from providing intra-hour

scheduling flexibility NERC notes that certain entities currently offer various forms of

scheduling on a 15-minutes basis and to date NERC is not aware of this causing any conflicts

with NERCrsquos Reliability Standards

Noting that the proposed 15-minute interval

was ldquoconsistent with the ideal time increments (ie 5 to 15 minutes) recommended by NERCrdquo

the Commission requested comment on whether there was any inconsistency among relevant

NERC Reliability Standards and the proposed intra-hour scheduling tariff reform

Yet NERC acknowledges that making a 15-minute scheduling interval more routine

including (critically) for inter-Balancing Area (BA) transactions would likely require review and

refinements to several existing Reliability Standards10

9 NOPR at P 37

In particular there would likely be a

need for changes to NERCrsquos Interchange Scheduling and Maintenance Coordination (INT)

Reliability Standards which were largely written based on the assumption that many schedules

will be on an hourly basis To the extent that this assumption has resulted in wording that is

consistent with an hourly regime interpretations or modifications to the INT Reliability

Standards would likely be required While it is expected that only minor wording changes to

affected standards may be necessary adopting interconnection-wide intra-hour scheduling could

have a substantial impact on practices and tools used by transmission operators to maintain

10 See eg NERC Reliability Standards BAL-005 R121 (Automatic Generation Control) BAL-006 R1 (Inadvertent Interchange) EOP-008 (Plans for Loss of Control Center Functionality) INT-001 R11 (Interchange Information) INT-004-2 (Dynamic Interchange Transaction Modifications) INT-005-003 (Interchange Authority Distributes Arranged Interchange) INT-006-3 (Response to Interchange Authority) INT-008 R1 (Interchange Authority Distributes Status)

5

reliable operations Time and attention to the details (regarding impacts and changes to

Reliability Standards practices and tools) would be required but a transition to more widespread

use of intra-hour scheduling flexibility is achievable in a reasonable time frame

However it should be noted that all creation and modification of Reliability Standards

must be considered as part of the NERC Reliability Standards Committee prioritization process

This prioritization process considers the regulatory reliability and logistical issues associated

with projects to create or modify NERC standards and helps determine the manner in which

industry resources and NERC staff are deployed to create or modify Reliability Standards

Additionally such changes must be developed in accordance with the steps outlined in the

NERC Standards Process Manual which ensures an open and inclusive process through

adherence to the standards development principles of the American National Standards Institute

In the NOPR the Commission proposed to ldquoallow all transmission customers the option

of submitting intra-hour schedules up to 15 minutes before the scheduling intervalrdquo11

bull communication time will be required as the request is transmitted received and

processed

NERC

notes that the INT Reliability Standards have been written so that nearly all schedules are

received at least 20 minutes ahead of the block-schedule start This 20-minute period was set to

provide the operator sufficient time to evaluate approve and implement the schedule request

For example if an Eastern Interconnection schedule request is submitted at 0040 for a schedule

that starts at 0100 then industry actions may include

bull the entities reviewing the request will require sufficient time to evaluate the

request

11 NOPR at 41

6

bull communication time will be required to verify that all entities have agreed to

implement the requested schedule and coordinate that agreement between all

entities and

bull entities will need time to input the request into their scheduling systems

When combined the required time is at least 15 minutes (0055) to perform these tasks with the

remaining time allowing for the initiation of the ramp which in the Eastern Interconnection is

based on the standard ramp of 10 minutes that straddles across the block-schedule start (eg

begin ramping at 0055 and complete ramping at 0105) Changes that impact this timing will

need to be accounted for in modifications to the associated INT Reliability Standards (ie INT-

005 and INT-008) and will result in significant changes in the way in which operators currently

process such requests As a result of this fairly tight advance notice time frame for processing

schedule changes any change to the existing 20-minute prior notice evaluation period for

schedules should be undertaken with caution

The Commission also requested comments regarding any changes that might be

necessary in hardware software or personnel As indicated above NERC is informed that

transmission providers offering and executing on 15 minute scheduling would require changes

(some substantial) to existing tools and processes used to perform scheduling and curtailment

activities For example the Interchange Distribution Calculator a tool which is used in the

Eastern Interconnection to manage congestion generally operates on an hourly basis as does the

Western Interconnections WebSAS tool In addition wide-spread intra-hour scheduling may

require system operators to adopt increasingly automated processes as significant aspects of

existing processes (ie check out) are often performed manually The need to account for

shorter-term schedules combined with the potential increase in volume of transactions

7

processed would in some instances require changes to both hardware and software NERC

believes such analysis would need to be performed subsequent to the issuance of a Final Rule (so

the requirements are known) but before implementation becomes mandatory

While NERC does not have personnel that would be directly impacted by the proposed

change NERC believes that entities that review and implement schedule requests would likely

see their personnel needs increase Such entities would also likely see increased demands on

their software and hardware associated with processing schedule requests


In the NOPR FERC proposed to define a VER as ldquoenergy source that (1) is renewable

(2) cannot be stored by the facility owner or operator and (3) has variability that is beyond the

control of the facility owner or operatorrdquo12


Noting that this definition is consistent with

NERCrsquos characterization of variable generation the Commission sought comment on the

proposed VER definition NERC supports the VER definition proposed by the Commission and

believes it is sufficient

In the NOPR the Commission requested comments ldquoon the extent to which some additional

type of contingency reserve service (beyond the services provided under Schedule 5 and 6 of the

12 NOPR at P 64 (citing NERC Accommodating High Levels of Variable Generation at 13-14 (2009) available at httpwwwnerccomfilesIVGTF_Report_041609pdf)

8

pro forma OATT) would ensure that VERs are integrated into the interstate transmission system

in a non-discriminatory manner while remaining consistent with NERC Reliability Standardsrdquo13

Large wind ramping events have characteristics that are both similar to and different than

conventional generator contingency events They are similar in that the large events are large and

infrequent They differ in that wind ramps are much slower than instantaneous contingency

events and the extreme wind ramps may be possible to forecast Figure 1 below shows a large

(1500 MW) wind ramp event that occurred in February 2007 in the Electric Reliability Council

of Texas (ldquoERCOTrdquo) region While this event is large and can present a serious operational

challenge it is a rare event occurring about once a year and it emerges slowly compared with a

conventional generation contingency which happens essentially instantaneously

Figure 1 ERCOT 2242007 wind event

The use of contingency reserves is similar to what is used to address large infrequent wind

ramps because contingency reserves are seldom deployed Typically contingency reserves are

split between spinning and non-spinning For large ramps lasting several hours the ramp

13 NOPR at P 100

9

duration make it difficult to include wind ramps as actual contingencies Resource and Demand

Balancing (BAL) Reliability Standard BAL-002 (Disturbance Control Performance) requires

ACE to be restored 15 minutes following the disturbance (R4) and the contingency reserves to be

restored within 105 minutes (90 minutes after the 15 minute disturbance recovery period ndash R6)

Both of these requirements can be problematic for wind ramps since they can be longer than the

disturbance recovery period as well as the reserve restoration period System operators typically

restore reserves much faster (within approximately ten minutes following the disturbance

recovery period) Therefore including two hour wind ramps as contingencies would also be

problematic

A further issue with a large long ramp is the point at which the event can be identified

For example during the ERCOT event in the Figure 1 above a full 20 minutes into the event it

may not be clear to the operator whether the wind power will continue declining or whether the

ramp is (nearly) over This highlights the importance of an accurate wind forecast so that wind

generators can schedule a reasonable forecast of their expected output

Still it may be appropriate to use contingency reserves in response to a portion of a wind

ramp Shared contingency reserves could be used to initiate the response allowing time for

alternate supply (or load reduction) to be implemented The frequency of ramp events would

need to be studied to determine which ramps are compatible with contingency reserve use The

industry should consider developing rules governing reserve deployment and restoration similar

to those that currently address conventional contingencies would also need to be developed

Some entities are considering rules that will allow contingency reserves to be deployed to

help manage large infrequent wind ramping events NERC believes that the industry should

consider how best to deal with this incremental risk Specifically NERC believes that further

10

analysis of how wind ramps can be recovered using contingency reserves should be undertaken

as well as consideration of how wind generation can minimize the impacts of wind ramps

through improved forecasting and market tools products and requirements The predictability

duration magnitude and ramp rate of an event are all important factors that are used in

determining how reserves for these events should be held

If Balancing Authorities can predict an occurring event and to some degree know the

duration magnitude and ramp rate of a future event they can use that information to ensure that

the correct reserve is ready to be deployed This type of analysis could potentially be done with

historic data that demonstrates the characteristics of the wind regime of the particular balancing

area (as shown in the Figure 1)

With improved forecasting systems real-time forecast information should also be used to

assist in determining what reserve requirements to hold for such events

V CONCLUSION

NERC is pleased to provide these comments in response to the Commissionrsquos NOPR and

looks forward to working with the Commission to ensure the successful integration of VERs

while maintaining the reliability of the bulk power system


Gerald W Cauley President and Chief Executive Officer David N Cook Sr Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet

s Willie L Phillips Holly A Hawkins Attorney Willie L Phillips Attorney North American Electric Reliability

Corporation 1120 G Street NW Suite 990 Washington DC 20005-3801 (202) 393-3998

11

(202) 393-3955 ndash facsimile hollyhawkinsnercnet williephillipsnercnet


I hereby certify that I have served a copy of the foregoing document upon all parties

listed on the official service list compiled by the Secretary in this proceeding

Dated at Washington DC this 2nd day of March 2011

s Willie L Phillips Willie L Phillips



February 28 2011

VIA ELECTRONIC FILING

Ms Kimberly D Bose Secretary Federal Energy Regulatory Commission 888 First Street NE Washington DC 20426

Re North American Electric Reliability Corporation

Docket No RM06-16-000 Dear Ms Bose

The North American Electric Reliability Corporation (ldquoNERCrdquo) hereby submits this

filing in compliance with Paragraph 629 of the Federal Energy Regulatory Commissionrsquos

(ldquoFERCrdquo) Order No 693 Order No 693 requires that NERC provide a quarterly informational

filing regarding the timeframe to restore power to the auxiliary power systems of US nuclear

power plants following a blackout as determined during simulations and drills of system

restoration plans This filing contains the referenced material pertaining to the fourth quarter of

2010

NERC also submits a request to terminate its obligation to file quarterly informational

filings as required by Paragraph 629 of Order No 693 on the basis that NERC has fulfilled the

intent of the directive With the implementation of the NUC-001-2 standard that was approved

by FERC on April 1 2010 more explicit requirements are now in place to address the off-site

power concerns expressed by the NRC Accordingly as explained in more detail herein the



express purpose of this data request that is the subject of these quarterly filings has been

superseded and the Commissionrsquos directives have been addressed

NERCrsquos filing consists of the following

bull This transmittal letter

bull A table of contents for the entire filing

bull A narrative description summarizing the data collected

bull Official Data Request to Fulfill FERC Order No 693 Requirements Restoration of Nuclear Power Plant Off-site Power Sources (Exhibit A) and

bull Restoration of Nuclear Power Plant Off-site Power Sources Data 4th Quarter 2010 (Exhibit B)

Please contact the undersigned if you have any questions


Holly Hawkins s Holly Hawkins






MANDATORY RELIABILITY STANDARDS ) Docket No RM06-16-000 FOR THE BULK POWER SYSTEM )




Holly A Hawkins Assistant General Counsel for Standards and

Critical Infrastructure Protection North American Electric Reliability Corporation 1120 G Street NW Suite 990 Washington DC 20005-3801 (202) 393-3998 (202) 393-3955 ndash facsimile hollyhawkinsnercnet

February 28 2011



TABLE OF CONTENTS

I Introduction 1

II Notices and Communications 2

III Summary of Restoration of Nuclear Power Plant Off-site Power Sources Data 2

IV Request to Terminate Data Collection Exercise 9 V Conclusion 13

EXHIBIT A ndash Official Data Request to Fulfill FERC Order No 693 Requirements Restoration of Nuclear Power Plant Off-site Sources EXHIBIT B ndash Restoration of Nuclear Power Plant Off-site Power Sources Data 4th Quarter 2010



1


FEDERAL ENERGY REGULATORY COMMISSION MANDATORY RELIABILITY STANDARDS ) Docket No RM06-16-000 FOR THE BULK POWER SYSTEM )



I

In its March 16 2007 Order

INTRODUCTION

1

1 Mandatory Reliability Standards for the Bulk-Power System 118 FERC para 61218 FERC Stats amp Regs para 31242 (2007) (Order No 693) Order on rehrsquog Mandatory Reliability Standards for the Bulk-Power System 120 FERC para 61053 (Order No 693-A) (2007)

the Federal Energy Regulatory Commission

(ldquoFERCrdquo) directed the North American Reliability Corporation (ldquoNERCrdquo) to provide a

quarterly informational filing regarding the timeframe to restore power to the auxiliary

power systems of US nuclear power plants following a blackout as determined during

simulations and drills of system restoration plans This filing includes information for the

fourth quarter of 2010 This filing also includes an explanation regarding why the data

collection exercise directed by FERC in Order No 693 is no longer necessary with the

implementation of the NUC-001-2 standard and the proposed EOP-005-2 standard

Given that the goal of the directive has been fulfilled continuing this reporting diverts

precious stakeholder regional entity and ERO resources from other activities



2

II


following


Gerald W Cauley President and Chief Executive Officer David N Cook Senior Vice President and General Counsel North American Electric Reliability Corporation 116-390 Village Boulevard Princeton NJ 08540-5721 (609) 452-8060 (609) 452-9550 ndash facsimile davidcooknercnet Persons to be included on the FERCrsquos service list are indicated with an asterisk



III

SUMMARY OF RESTORATION OF NUCLEAR POWER PLANT OFF-SITE POWER SOURCES DATA

Background

In response to comments offered by the US Nuclear Regulatory Commission

during the Notice of Proposed Rulemaking process FERC expressed in Order No 693

its concern regarding the role and priority that nuclear power plants should have in bulk

power system restoration plans FERC addressed the concern in the discussion of the

EOP-005-1 mdash System Restoration Plans Reliability Standard Specifically in Paragraph

629 of Order No 693 FERC directed NERC as follows



3

In addition the [FERC] directs the ERO to gather data pursuant to sect395(f) of the [FERCrsquos] regulations from simulations and drills of system restoration on the time it takes to restore power to the auxiliary power systems of nuclear power plants under its data gathering authority and report that information to [FERC] on a quarterly basis

EOP-005-1 Requirement R11 and sub-requirement R114 identify the expected

priority for restoring off-site power to nuclear stations They state

R11 Following a disturbance in which one or more areas of the Bulk Electric System become isolated or blacked out the affected Transmission Operators and Balancing Authorities shall begin immediately to return the Bulk Electric System to normal

R114 The affected Transmission Operators shall give high priority to

restoration of off-site power to nuclear stations

Importantly while the requirement provides the instruction to give high priority to

off-site power restoration it does not specify target timeframes

NERC in its role as the Electric Reliability Organization (ldquoEROrdquo) and in

accordance with 18 CFR sect 392(d) is required to provide information as necessary to

FERC in order to implement section 215 of the Federal Power Act As such users

owners and operators of the bulk power system are required to provide the ERO with

information in support of this same objective

To collect the data necessary to respond to the FERC directive for nuclear power

plant off-site power source data NERC issued a data request process that was at that

time drafted as a proposed rule of procedure This procedure required NERC to post a

proposed ERO data request for industry comment followed by NERC Board of Trustees

approval before issuing it as a formal data request2

2 FERC has since approved Section 1600 of the Rules of Procedure known as the Data Rule which establishes the process for issuing ERO data requests

NERC posted the ldquonuclear data

requestrdquo for a 30-day industry comment period that began on June 26 2007 NERC



4

reviewed the comments received and presented a final version of the data request that

was adopted by the NERC Board of Trustees at its August 2 2007 meeting

The data presented in Exhibit B to this filing contains critical energy

infrastructure information Specifically the information set forth in Exhibit B to the

instant filing includes critical energy infrastructure information as defined by FERC

Rules of Practice and Procedure (18 CFR Part 388) FERC Orders and NERC Rules of

Procedure The information pertains to proprietary or business design information

including design information related to vulnerabilities of critical energy infrastructure

information that is not publicly available Accordingly the information set forth in

Exhibit B has been redacted from the public filing In accordance with the FERC Rules

of Practice and Procedure 18 CFR sect 388112 a non-public version of the information

redacted from the public filing is being provided under separate cover NERC requests

that the confidential non-public information be provided special treatment in accordance

with the above regulation

The ERO data request for nuclear power plant off-site power source restoration

data as approved by the NERC Board of Trustees is found in Exhibit A Following

Board of Trustees approval NERC began to collect nuclear data from US Transmission

Operators during the fourth quarter 2007 and will continue to collect the data quarterly

until otherwise directed by FERC This filing represents data captured for the fourth

quarter of 2010

The specific data requested of the Transmission Operators requests the following

information

bull Reporting entity

bull Name of exercise drill or simulation



5

bull Date of exercise drill or simulation

bull Name of nuclear plant

bull Unit designation (each unit must be included separately)

bull Identifier of off-site power source

bull Time duration when off-site power sources are lost to the restoration of first off-site power source (For this request the loss of off-site power sources is the simulated physical interruption of power in support of EOP-005-1 requirements) and

bull Discussion of scenario assumptions or constraints impacting the restoration of the initial off-site power source to the nuclear power plant

In addition the following clarifying language was included in the data request to

guide the Transmission Operators when supplying the requested data

Simulations drills or exercises that are implemented for individualized operator training requirements are not included in this request Simulations drills and exercises conducted to support the requirements of EOP-005-1 are included in this request This request is not intended to require additional simulations or studies to those conducted to satisfy EOP-005-1 requirements

It is important to note that EOP-005 focuses on restoration plans and does not contain any

requirement for restoration plans specific to nuclear plants Accordingly the reporting

conducted under this data request so far will not result in a tabulation resulting in reports

for each US nuclear plant

Exhibit B presents the raw data collected through this period of observation As

noted above for the public version of this report Exhibit B has been redacted to remove

the actual raw data collected through the period of observation in accordance with the

data survey and in recognition that the information requested constitutes confidential

critical energy infrastructure information Specifically Exhibit B contains information

that if released could identify system weaknesses and pose a risk of attack on existing

infrastructure NERC respectfully requests that the critical energy infrastructure



6

information be protected consistent with national energy security objectives and in

accordance with the cited regulation

NERC has not analyzed this data to identify the impact of the reported off-site

power source restoration times relative to the ability of the US nuclear power plants to

remain in a mode that permits a timely return to service However NERC will utilize the

information contained herein to ensure applicable entities are supporting their reliability

standard obligations as defined in EOP-005-1 relative to the priority of off-site power

source restoration to nuclear power plants in plans for system restoration

Summary of Data

There are a total of 104 nuclear units in the US Of these 44 were included in

exercises drills or simulations in support of EOP-005-1 in the fourth quarter of 2010

Overall Transmission Operators conducted a total of 41 individual exercises drills or

simulations during this period that included the restoration of off-site power sources to

the 44 units with many events impacting more than one nuclear unit For example an

entity conducted one system restoration exercise on October 12 2010 that involved the

restoration of offsite power sources to a total of three nuclear units In the summary chart

that follows below each offsite power source restoration ldquoeventrdquo is reported separately

for purposes of data analysis In total one hundred twenty two (122) off-site power

source restoration ldquoeventsrdquo are included in the raw data presented in Exhibit B of this

filing



7

Of the one hundred twenty two (122) events there were ninety-four (94)3

NERC categorized the restoration of first off-site sources in two-hour windows

Over eighty-eight (88) percent (83 of 94) of the initial off-site power source restorations

occurred within the first six hours following the simulated blackout event with over

forty-eight (48) percent (46 of 94) occurring in two hours or less Twenty-three (23)

sources were simulated to be restored in the 2 to 4 hour window

potential initial off-site source restorations (some units have multiple off-site sources)

The remaining twenty-eight (28) events included in the data involved the restoration of a

subsequent off-site source beyond the first source restored Of the twenty-eight (28)

events one (1) subsequent source was simulated to be restored in less than 2 hours three

(3) sources in the 2 to 4 hour window thirteen (13) sources were simulated to be restored

in the 4 to 6 hour window three (3) sources were simulated to be restored in the 6 to 8

hour window eight (8) sources were simulated to be restored in the 8 to 10 hour window

Total Number Offsite Power Source Restoration Events Included in EOP-005-1 Exercises Drills or Simulations

94

Potential first off-site source restorations

46

Exercises Drills or Simulations in which the first off-site source was restored in 2 hours or less following the loss of

power

23


14


0


0

3 Not all units provided data for off-site sources beyond the first source restored The data included represents only the units that provided the data and does not include the entire spectrum of off-site sources beyond the initial source for the rest of the units



8

Exercises Drills or Simulations in which the first off-site

source was restored 8-10 hours following the loss of power

1

Exercises Drills or Simulations in which the first off-site source was restored more than 10 hours following the loss of

power

10

Exercises Drills or Simulations that did not achieve the restoration of the first off-site power source to a nuclear

power plant or that did not report a time for source restoration

0



9

IV

REQUEST TO TERMINATE DATA COLLECTION EXERCISE

NERC has collected data in support of the FERC request for twelve quarters

Paragraph 625 of Order No 693 summarized the comments from the Nuclear Regulatory

Commission (ldquoNRCrdquo) in response to the then-proposed EOP-005-1 Reliability Standard

625 NRC suggests that this Reliability Standard include (1) a requirement to record the time it takes to restore power to the auxiliary power systems of nuclear power plants (2) a provision stating that the affected transmission operators shall give high priority to restoration of off-site power to nuclear power plants whether or not a nuclear power plant is being powered from the nuclear power plantrsquos onsite power supply and (3) a provision stating that restoration shall not violate nuclear power plant minimum voltage and frequency requirements

In response FERC noted in Paragraph 629 that

629 NRC raises several issues concerning the role and priority that nuclear power plants should have in system restorations The Commission shares these concerns and directs the ERO to consider the issues raised by NRC in future revisions of the Reliability Standard through the Reliability Standards development process In addition the Commission directs the ERO to gather data pursuant to sect 395(f) of the Commissionrsquos regulations from simulations and drills of system restoration on the time it takes to restore power to the auxiliary power systems of nuclear power plants under its data gathering authority and report that information to the Commission on a quarterly basis

Since the issuance of FERCrsquos Order No 693 in March 2007 NERC has

addressed the issues raised by the NRC in its development of the NUC-001-2 Reliability

Standardmdash Nuclear Plant Interface Coordination that was approved by FERC on April 1

2010 The NUC-001-2 standard requires a Nuclear Plant Generator Operator to

coordinate operations and planning with Transmission Entities providing services relating

to nuclear plant operating and off-site power delivery requirements NUC-001-2 also

requires Nuclear Plant Generator Operators and Transmission Entities to execute and



10

implement interface agreements setting forth expectations and procedures for

coordinating operations to meet the nuclear plant licensing requirements and system

operating limits affecting nuclear plant operations

The Commissionrsquos specific concerns in Paragraph 629 of Order No 693 are

addressed by the Requirements of the NUC-001-2 standard For example in Order No

693 the Commission directed NERC to gather data from simulations and drills of system

restoration on the time it takes to restore power to the auxiliary power systems of nuclear

power plants The currently-effective Requirement R922 of NUC-001-2 requires

Nuclear Plant Generator Operators to identify facilities components and configuration

restrictions that are essential for meeting the Nuclear Interface Plant Requirements

(ldquoNPIRsrdquo) Requirement R934 includes provisions to address mitigating actions needed

to avoid violating NPIRs and to address periods when responsible Transmission Entities

lose the ability to assess the capability of the electric system to meet the NPIRs (emphasis

added) These provisions also include the obligation to notify the Nuclear Plant

Generator Operator of this information within a specified time frame

Additionally Requirement R935 of NUC-001-2 includes provisions for

considering within the restoration process the requirements and urgency of a nuclear

plant that has lost all off-site and on-site AC power Requirement R4 provides that the

applicable Transmission Entities shall incorporate the NPIRs into their operating analyses

of the electric system operate the electric system to meet the NPIRs and inform the

Nuclear Plant Generator Operator when the ability to assess the operation of the electric

system affecting NPIRs is lost



11

The current data request that NERC issued in 2007 to begin collecting the data

required by these quarterly compliance filings was limited to those instances where drills

were conducted under EOP-005 Given the fact that a broader approach involving the

establishment of NPIRs under the NUC-001-2 standard is now in place specifically to

address the off-site power capability concerns of the NRC the Commissionrsquos concerns

on this issue that were raised in Order No 693 have been addressed

Similarly NERC filed EOP-005-2 mdash System Restoration from Blackstart

Resources for FERC approval on December 31 2009 In it the Transmission Operator

shall have a Reliability Coordinator-approved restoration plan that includes ldquo[a]

description of how all Agreements or mutually agreed upon procedures or protocols for

off-site power requirements of nuclear power plants including priority of restoration will

be fulfilled during System restorationrdquo

The Commission issued a Notice of Proposed Rulemaking on the System

Restoration Reliability Standards which includes NERCrsquos proposed EOP-005-2

Reliability Standard on November 18 2010 (lsquoNovember 18 NOPRrdquo)4 In the November

18 NOPR FERC proposed to approve the EOP-005-2 standard stating that the proposed

Reliability Standard effectively addresses the Commissionrsquos directive in Order No 693 to

develop timeframes for training and review of restoration plan requirements to simulate

contingencies and prepare operators for anticipated and unforeseen events5

On the basis that the more explicit requirements contained in the FERC-approved

NUC-001-2 standard and the proposed EOP-005-2 standard are now either in place or

NERC

responded to the Commissionrsquos November 18 NOPR on January 24 2011

4 System Restoration Reliability Standards Notice of Proposed Rulemaking 133 FERCpara61161 (November 18 2010) 5 Id at P 19



12

awaiting FERC approval NERC submits that the express purpose of conducting the data

request that is the subject of this filing has been superseded Considering this point and

the significant level of effort for Transmission Operators to collect and forward the

information to the Regional Entity the Regional Entityrsquos effort to accumulate and

assemble the data and NERCrsquos efforts to combine the information into the filings that

have been submitted NERC believes it is appropriate to redirect these resources to other

reliability activities with greater impact on the reliability of the bulk power system and

more efficient use of industry regional and ERO resources NERC therefore respectfully

requests that FERC terminate NERCrsquos obligation to collect and file the data called for

under this program



13

IV

NERC respectfully requests that FERC accept this informational filing for the

fourth quarter of 2010 in accordance with FERCrsquos directive that NERC provide

information regarding the time it takes to restore off-site power sources to nuclear power

plants following a blackout as determined by drills and simulations Additionally NERC

requests that FERC terminate the ongoing obligation to collect and file such data on the

basis that new standards approved by FERC or pending FERC approval contain more

explicit instructions regarding expectations of the Transmission Operators for restoring

off-site power sources to nuclear power plants following a service interruption

CONCLUSION



s Holly Hawkins






I hereby certify that I have served a copy of the foregoing document upon all

parties listed on the official service list compiled by the Secretary in this proceeding

Dated at Washington DC this 28th

day of November 2010

Holly A Hawkins s Holly A Hawkins




Exhibit A

Official Data Request to Fulfill FERC Order No 693 Requirements Restoration of

Nuclear Power Plant Off-site Power Sources



August 24 2007

TRANSMISSION OPERATOR CONTACT TITLE COMPANY ADDRESS CITY STATE ZIP CODE (TNR 12pt) Dear XXXXX

Official Data Request to Fulfill FERC Order No 693 Requirements Restoration of Nuclear Power Plant Off-site Power Sources

Pursuant to the authority granted by FERC Order 672 and as implemented in Title 18 Section 392 of the Code of Federal Regulations NERC as the appointed electric reliability organization issues this official data request as described in Attachment 1 The legal basis in the United States for this authority is explained in FERCrsquos Order 672 paragraph 114

114 The Commission agrees with commenters that to fulfill its obligations under this Final Rule the ERO or a Regional Entity will need access to certain data from users owners and operators of the Bulk-Power System Further the Commission will need access to such information as is necessary to fulfill its oversight and enforcement roles under the statute Section 392 of the regulations will include the following requirement

(d) Each user owner or operator of the Bulk-Power System within the United States (other than Alaska and Hawaii) shall provide the Commission the Electric Reliability Organization and the applicable Regional Entity such information as is necessary to implement section 215 of the Federal Power Act as determined by the Commission and set out in the Rules of the Electric Reliability Organization and each applicable Regional Entity The Electric Reliability Organization and each Regional Entity shall provide the Commission such information as is necessary to implement section 215 of the Federal Power Act

Within the United States failure to comply with an official data request would constitute a violation of FERC regulations Enforcement action is available to FERC to deal with

Gerry Adamski Vice President and

Director of Standards



violations of its regulations This is authority FERC could exercise not authority available to NERC NERCrsquos Compliance Monitoring and Enforcement Program including the ability to impose penalties and sanctions is limited to violations of reliability standards Please note the following additional pieces of information relative to this data request

bull An Excel spreadsheet (attached) to serve as a template for providing the requested information

bull Regional entities are requested to submit the requested information to sarcommnercnet

Thank you for your support of this effort Please contact me should you have any questions Sincerely

Enclosure cc James D Castle Chairman Operating Reliability Subcommittee

Regional Entity Management Group



Exhibit A Restoration of Nuclear Power Plant Offsite Power Source Data Request

Background In paragraph 629 of Order No 693 FERC directs NERC to provide an informational filing regarding the timeframe to restore auxiliary power to nuclear power plants following a blackout as determined during simulations and drills of system restoration plans

629 ldquoIn addition the Commission directs the ERO to gather data pursuant to sect 395(f) of the Commissionrsquos regulations from simulations and drills of system restoration on the time it takes to restore power to the auxiliary power systems of nuclear power plants under its data gathering authority and report that information to the Commission on a quarterly basisrdquo

Description of Data Requested This request is an ongoing request that begins in the fourth quarter of 2007 If an exercise drill or simulation includes the restoration of one or more offsite power sources to a nuclear power plant the following information is to be prepared and provided for each offsite power source in a format developed and provided by NERC

bull Reporting entity bull Name of exercise drill or simulation bull Date of exercise drill or simulation bull Name of nuclear plant bull Unit designation (each unit must be included separately) bull Identifier of offsite power source bull Time duration when offsite power sources are lost to the restoration of first

offsite power source (For this request the loss of offsite power sources is the simulated physical interruption of power in support of EOP-005-1 requirements)

bull Discussion of scenario assumptions or constraints impacting the restoration of the initial offsite power source to the nuclear power plant

Simulations drills or exercises that are implemented for individualized operator training requirements are not included in this request Simulations drills and exercises conducted to support the requirements of EOP-005-1 are included in this request This request is not intended to require additional simulations or studies to those conducted to satisfy EOP-005-1 requirements The individual data submissions should be submitted to the regional entity who will compile the data in a consolidated format The regional entity will then forward the complied data to NERCrsquos director of standards on a quarterly basis To comply with FERC directives NERC will make a quarterly filing with FERC that includes the compiled data



How the Data Will Be Used The data will be provided to FERC per its directive in Order 693 FERC agrees with issues raised by the Nuclear Regulatory Commission (NRC) concerning the role and priority nuclear power plants should have in system restorations and directs the collection of this data to aid in its review of this issue How the Data Will Be Collected and Validated The regional entities are requested to coordinate the collection and composite presentation of the requested data from its member participants Transmission operators responsive to this request are expected to validate the data to be correct prior to submittal Reporting Entities Each transmission operator in the United States who has a nuclear power plant tied to a transmission line that it controls and who is participating in an exercise drill or simulation in support of the EOP-005-1 standard will report Transmission operators that do not have a nuclear power plant tied to a transmission line it controls are exempt from this request Transmission operators outside the United States subject to EOP-005-1 are voluntarily encouraged to submit this information as well NERC will seek permission from these non-US entities for inclusion of its data in the information filed with FERC Due Date for the Information If a transmission operator subject to this data request conducts a drill simulation or exercise that includes restoration of the initial offsite power source to a nuclear power plant the transmission operator is to submit the requested information to its regional entity by the fifteenth of the month following the end of the previous three-month quarter The regional entity is to provide a quarterly report of all such submissions by April 30 July 31 October 31 and January 31 for the three-month period that concludes on these dates This data request begins in the fourth quarter of 2007 If no drill exercise or simulation meeting the criteria described above is conducted during a quarter no submission by the transmission operator and regional entity is required This data request does not direct transmission operators to conduct quarterly exercises drills or simulations to satisfy this data request It does require the data to be reported if such a simulation drill or exercise is conducted Restrictions on Disseminating Data (ConfidentialCEII) NERC will provide this data to FERC per its Order No 693 directives This information will be treated as critical energy infrastructure information when submitted to FERC Estimate on Burden Imposed to Collect Data There will be ongoing costs for the staff of responsible entities to respond and for regional entities to collect compile and report to NERC the requested data



Exhibit B

Restoration of Nuclear Power Plant Off-site Source Data 4th Quarter 2010


Document Content(s)

Final_NUC_filing_DraftQ42010_20110228(PUBLIC)PDF1-24


From Guy V ZitoTo grpStaffSubject FW AnswerResponse to a PleadingMotion submitted in FERC RM06-16-000 by North American Electric

Reliability Corporationet alDate Wednesday March 02 2011 95543 AM

NERC had filed a motion to cease developing and submitting quarterly reports for the timeframe torestore auxiliary power to Nuclear units The submission states that with the new NUC-001-2 theprevious directives in Order 693 have been addressed I will keep staff informed as FERC rules on this

Thanks

Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax________________________________________From FERC eSubscription [eSubscriptionfercgov]Sent Tuesday March 01 2011 740 AMSubject AnswerResponse to a PleadingMotion submitted in FERC RM06-16-000 by North AmericanElectric Reliability Corporationet al

On 2282011 the following Filing was submitted to the Federal Energy Regulatory Commission (FERC)Washington DC

Filer North American Electric Reliability Corporation North American Electric Reliability Corp (as Agent) North American Electric Reliability Corporation North American Electric Reliability Corp (as Agent)

Docket(s) RM06-16-000Filing Type AnswerResponse to a PleadingMotionDescription Fourth Quarter 2010 Compliance Filing of the North American Electric ReliabilityCorporation in Response to Paragraph 629 Of Order No 693 and Request to Terminate ComplianceFiling Obligation in Docket No RM06-16-000

To view the document for this Filing click herehttpelibraryFERCgovidmwsfile_listaspaccession_num=20110228-5264



From Guy V ZitoTo rscSubject FW Commission OrderOpinion issued in FERC RM06-22-014Date Thursday March 10 2011 73744 PMImportance High

FYI

Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax________________________________________From Guy V ZitoSent Thursday March 10 2011 726 PMTo grpStaffSubject FW Commission OrderOpinion issued in FERC RM06-22-014

To All

FYI FERC dismisses the NERCs compliance filing regarding Implementation Plans and ldquoscope ofsystems determinationrdquo for Nuclear units The ldquoscope of systems determinationrdquo identifies whichsystems structures and components within the balance of plant at nuclear power facilities will besubject to NRCrsquos cyber security regulations and which will be subject to NERCrsquos CIP Standards This ispursuant to the MOU between the NRC and FERC NRCs cyber security rule covers the balance of plantof the Nuclear Units that was in question

Thank-you

Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax________________________________________From FERC eSubscription [eSubscriptionfercgov]Sent Thursday March 10 2011 606 PMSubject Commission OrderOpinion issued in FERC RM06-22-014

On 3102011 the Federal Energy Regulatory Commission (FERC) Washington DC issued thisdocument

Docket(s) RM06-22-014Filing Type Commission OrderOpinionDescription Order dismissing compliance filing re Mandatory Reliability Standards for CriticalInfrastructure Protection under RM06-22

To view the document for this Issuance click herehttpelibraryFERCgovidmwsfile_listaspaccession_num=20110310-3042



130 FERC para 61185 UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION Before Commissioners Jon Wellinghoff Chairman Marc Spitzer Philip D Moeller and John R Norris Mandatory Reliability Standards for Critical Infrastructure Protection

Docket No RM06-22-011

ORDER ADDRESSING COMPLIANCE FILING AND APPROVING IMPLEMENTATION PLAN

(Issued March 18 2010)

1 On January 19 2010 the North American Electric Reliability Corporation (NERC) submitted a compliance filing in response to the Commissionrsquos December 17 2009 order1 addressing NERCrsquos plan for the implementation of eight Critical Infrastructure Protection Reliability Standards CIP-002-1 through CIP-009-1 (CIP Standards) by generator owners and operators of nuclear power plants located in the United States (Implementation Plan)

2 In this order we accept NERCrsquos compliance filing and approve the Implementation Plan for nuclear power plant generator ownersrsquo and operatorsrsquo compliance with Version 1 of the CIP Standards to become effective on the date of this order In addition the Commission directs NERC to make a compliance filing submitting implementation plans for the implementation of Versions 2 and 3 of the CIP Standards by owners and operators of US nuclear power plants on the same schedule established for Version 1 under the Implementation Plan

I Background

3 In Order No 706 the Commission approved Version 1 of the CIP Standards CIP-002-1 through CIP-009-12 The CIP Standards require certain users owners and

(continuedhellip)

1 Mandatory Reliability Standards for Critical Infrastructure Protection 129 FERC para 61224 (2009) (December 17 Order)

2 Mandatory Reliability Standards for Critical Infrastructure Protection Order No 706 122 FERC para 61040 at P 86-90 order on rehrsquog Order No 706-A 123 FERC

Docket No RM06-22-010 - 2 -

operators of the Bulk-Power System to comply with specific requirements to safeguard critical cyber assets The Commission also directed NERC to develop certain modifications to the CIP Standards3

4 Each Version 1 CIP Standard provides that facilities regulated by the US Nuclear Regulatory Commission (NRC) are exempt from complying with the CIP Standard4 On March 19 2009 the Commission issued Order No 706-B clarifying that because the NRC regulations do not extend to all equipment within a nuclear power plant the CIP Standards apply to the ldquobalance of plantrdquo equipment within a nuclear power plant located in the United States that is not regulated by the NRC5 In Order No 706-B the Commission directed NERC to engage in a stakeholder process to develop a more appropriate timeframe for nuclear power plantsrsquo full compliance with the CIP Standards and to submit a compliance filing that sets forth a proposed implementation plan for nuclear power plants to comply with the CIP Standards6

5 On May 22 2009 NERC filed revised CIP Standards Version 2 in compliance with Order No 706 By order issued September 30 2009 the Commission approved the Version 2 CIP Standards to become effective on April 1 20107 The Commission clarified that the September 30 Order does not alter its findings in Order No 706-B regarding the applicability of the CIP Standards and associated implementation timetables to facilities located at nuclear power plants8

6 On September 15 2009 in compliance with Order No 706-B NERC filed the Implementation Plan for the implementation of Version 1 of the CIP Standards by generator owners and operators of nuclear power plants9 With the exception of CIP- para 61174 (2008) order on clarification Order No 706-B 126 FERC para 61229 (2009)

3 Order No 706 122 FERC para 61040 at P 25

4 Order No 706-B 126 FERC para 61229 at P 1

5 Id

6 Id P 60

7 North American Electric Reliability Corp 128 FERC para 61291 (2009) (September 30 Order)

8 Id P 13

9 NERC Sept 15 2009 Compliance Filing and Petition for Approval of Implementation Plan Docket No RM06-22-10 (NERC September 15 Petition)

Docket No RM06-22-010 - 3 -

002-1 R1 and R210 the Implementation Plan is structured such that the timelinecompliance for each requirement within the CIP Standards is the later of (i) the Commission-approved effective date of the Implementation Plan (designated as ldquoRrdquo) plus 18 months (R + 18 months) (ii) the date the scope of systems determination is completed (designated as ldquoSrdquo) plus 10 months (S + 10 months) or (iii) if an outage is required for implementation six months following the completion of the first refueling outage at least 18 months following the Commissionrsquos effective date

for

11 NERC stated that the ldquoscope of systems determinationrdquo includes establishing the NERC and NRC jurisdictional delineation for systems structures and components12 that is predicated upon the completion of a NERC-NRC memorandum of understanding as well as the creation of an exemption process for excluding certain systems structures and components from the scope of NERC CIP Standards as provided for in Order No 706-B13

7 By order issued on December 17 2009 the Commission requested that NERC submit additional information regarding the scope of systems determination to assist the Commissionrsquos evaluation of the Implementation Plan14 Specifically we directed NERC to provide the following information to help the Commission evaluate whether the Implementation Plan provides an appropriate schedule to make the CIP Standards mandatory and enforceable for generator owners and operators of US nuclear power plants

the anticipated date the scope of systems determination framework will be finalized

the status of the development of the exemption process

10 CIP-002-1 R1 and R2 pertain to the identification of critical assets which is a

preliminary step for implementing of the remainder of the CIP Standards Accordingly the Implementation Plan calls for CIP-002-1 R1 and R2 to be completed within 12 months of the Commission-approved effective date of the Implementation Plan See NERC September 15 Petition at Exhibit A 3

11 Id at Exhibit A 2

12 The phrase ldquostructures systems and componentsrdquo refers to any element of equipment systems or networks of equipment or portions within a nuclear power plant within an entityrsquos ownership or control See Order No 706-B at P 15

13 See NERC Petition at Exhibit A 2 see also Order No 706-B at P 50

14 December 17 Order 129 FERC para 61224 at P 2 and 14

Docket No RM06-22-010 - 4 -

whether the exemption process will include (i) an application deadline and (ii) a deadline for a determination on an exemption request and

a description of any other time parameters that may be included in the exemption process15

In addition the Commission directed NERC to make a compliance filing incorporating into the Implementation Plan the implementation of Version 2 of the CIP Standards by nuclear power plants on the same schedule established for Version 116

II NERC Compliance Filing

8 In response to the Commissionrsquos information request NERCrsquos January 19 Compliance Filing explains its process for making the scope of systems determination and provides a project timeline for completing the scope of systems determination17 According to NERCrsquos Compliance Filing it will use a ldquoBright-Line Testrdquo to make its scope of systems determination18 The Bright-Line Test will identify which systems structures and components in a nuclear power plantrsquos balance of plant are subject to NERCrsquos CIP Standards and which are subject to the NRCrsquos jurisdiction In its Compliance Filing NERC reiterates its request that the Commission approve the Implementation Plan as it relates to the implementation of Version 1 of the CIP Standards with an immediate effective date

9 NERC stated in its September 15 2009 Petition that the scope of systems determination would be predicated upon the completion of a memorandum of understanding (MOU) between NERC and the NRC The MOU was executed on December 30 200919 The MOU sets forth and coordinates NERCrsquos and the NRCrsquos

(continuedhellip)

15 Id P 14

16 Id P 15

17 NERC January 19 2010 Compliance Filing in Response to the Commissionrsquos December 17 2009 Order Addressing Compliance Filing and Requiring Further Compliance Filing (Compliance Filing)

18 NERCrsquos Compliance Filing appears to use the terms ldquoBright-Line Testrdquo ldquoBright-Line exemption processrdquo and ldquoBright-Line determinationrdquo interchangeably to refer to the ldquoexemption processrdquo NERC has developed to make its scope of systems determination

19 Compliance Filing at 6 NERC submitted a copy of the MOU as Exhibit 1 to

Docket No RM06-22-010 - 5 -

respective roles and responsibilities related to the application of each of their cyber security requirements20 Under the rubric of the MOU NERC and NRC are collaborating on the development of an ldquoin-scoperdquo system list to clarify which systems structures and components at nuclear power facilities will be subject to NRCrsquos security regulations and which will be subject to the CIP Reliability Stand 21

cyber ards

10 According to NERC to make the scope of systems determination using its Bright-Line Test NERC will follow a two part process First NERC will conduct workshops followed by the Bright-Line documentation process Specifically NERC states that it plans to conduct a series of regional workshops for nuclear plants licensed by the NRC (licensees) to facilitate the development of a Bright-Line Survey and to communicate expectations for licenseesrsquo completion of the Survey22 At the workshops NERC will present a preliminary Bright-Line Survey that the licensees will modify to the specifics of their respective facilities The Survey is intended to gather detailed information about each licenseersquos systems structures and components and will require the licensees to identify all systems structures and components with cyber assets Shortly after the workshops NERC will distribute the Bright-Line Survey to each licensee The completed surveys will be due back to NERC within 30 days Beginning in June or July of 2010 NERC will verify the survey results through facility site visits if necessary Once verified NERC and the NRC will use the survey results to make the scope of systems determination

A Date the Scope of Systems Determination Framework Will Be Finalized

11 With respect to the anticipated date the scope of systems determination framework will be finalized NERC states that it plans to finalize the scope of systems determinations within 8 months of the date the Implementation Plan becomes effective (referred to by NERC as ldquoR + 8 monthsrdquo) This projected timeframe is based on the assumption that the effective date for the Implementation Plan will be April 1 2010 This timeline would ensure that there would be no significant gap between the compliance date linked to the Commission effective date (scenario (i) under the Implementation Plan R + 18) and the compliance deadline linked to the scope of systems

the Compliance Filing

20 See MOU at I3

21 Compliance Filing at 6

22 Id at 7-8

Docket No RM06-22-010 - 6 -

determination (scenario (ii) under the Implementation Plan S + 10) NERC further notes that the scope of systems determination may be later for entities with requirements tied to a specific plant outage

B Status of the Development of the Exemption Process

12 In response to the Commissionrsquos question regarding the status of the development of the exemption process NERC states that the exemption process ie the Bright-Line Test started with the planning of the regional workshops NERCrsquos Bright-Line determination project timeline broken down by task is included with its Compliance Filing as Exhibit 2

C Whether the Exemption Process Includes Deadlines for Applications and Determinations

13 With regard to whether the exemption process will include an application deadline or a determination deadline NERC states that there will be a deadline for submitting ldquothe necessary informationrdquo presumably the Bright-Line Survey Based on NERCrsquos statement that ldquothe determination of a Licenseesrsquo scope of systems to be exempted from compliance with the NERC CIP Reliability Standards must be made no later than R + 8 monthsrdquo23 it appears that NERC intends to complete the exemption process within eight months of the Commission-approved effective date for the Implementation Plan According to NERC this timeframe will ensure that the compliance deadline for licensees subject to a scope of systems determination will track the standard compliance deadline ie R + 18 months

D Other Time Parameters

14 In response to the question regarding any other time parameters that may be included in the exemption process NERC notes that its projected schedule is ldquocontingent upon NRC resourcesrdquo24

E Implementation of Version 2 and 3 of the CIP Standards

15 In response to the Commissionrsquos directive regarding the inclusion of the implementation of Version 2 of the CIP Standards into the Implementation Plan NERC requests permission to submit an additional compliance filing requesting Commission approval of the Version 2 and Version 3 implementation plans for US nuclear owners

23 Id at 9

24 Id at 9-10

Docket No RM06-22-010 - 7 -

and operators after the plans have been balloted by the industry and approved by the NERC Board of Trustees NERC states that it is in the process of developing the CIP Version 2 and 3 implementation plans for nuclear facilities but could not complete the balloting process within the 30 day compliance deadline set by the December 17 Order NERC asserts that the deadline for US nuclear power plant ownersrsquo and operatorsrsquo compliance with the Version 2 and Version 3 CIP Standards will mirror the Implementation Plan for Version 1 of the CIP Standards as required by the December 17 Order25 In addition NERC states that it ldquowill include for all future filings of proposed new versions of the CIP-002 through CIP-009 standards an associated Implementation Plan that addresses US Nuclear Power Plant Owners and Operators compliance to the proposed requirementsrdquo26

III Notice and Responsive Pleadings

16 Notice of NERCrsquos Compliance Filing was published in the Federal Register with interventions and protests due on or before February 9 201027 On February 9 2010 Exelon Corporation (Exelon) filed comments

17 Exelon notes that NERCrsquos plan for completing the Bright-Line determination does not include a contingency for delays Thus Exelon is concerned with NERCrsquos assertion that ldquothe determination of a Licenseesrsquo scope of systems to be exempted from compliance with the NERC CIP Reliability Standards must be made no later then R + 8 monthsrdquo28 Exelon states that NERCrsquos ldquoformula R + 8 months may not give licensees the full time intendedrdquo to seek an exemption29 Exelon asserts that licensees must know what systems are subject to NERCrsquos jurisdiction before they can invoke NERCrsquos exemptions process to avoid dual regulation To resolve this issue Exelon requests that the Commission condition its approved effective date (R) on the actual date that the Bright-Line determination is finalized

18 Exelon raises two additional concerns First Exelon states that the Bright-Line determination may conflict with the NRCrsquos Critical Digital Asset assessment process noting that as the NRCrsquos Critical Digital Asset assessments progress ldquothe rationale for

25 Id at 11

26 Id at 10

27 75 Fed Reg 4374 (Jan 27 2010)

28 Exelon Comments (quoting Compliance Filing at 9)

29 Id

Docket No RM06-22-010 - 8 -

NERC exemptions may become more clearly definedrdquo30 To alleviate this concern Exelon requests that the Commission direct NERC either to consider the timing of the NRCrsquos Critical Digital Asset assessment process in its Bright-Line determination plan or to provide for an ongoing exemptions process in lieu of a finite completion date Second Exelon ldquorequests that NERC provide clear guidance on the scope of the proposed [Bright-Line] surveyrdquo and asks that the Commission direct NERC to extend the 30 day deadline for licensees to complete the survey31

IV Commission Determination

19 In the December 17 Order we stated that the ldquogeneral structure of the Implementation Plan comports with the directives in Order No 706-Brdquo32 However because the Implementation Plan is structured such that the compliance date is the later of three scenarios one of which is tied to the completion of NERCrsquos scope of systems determination absent information regarding NERCrsquos scope of systems determination the Commission could not determine whether the implementation timeline established an adequate degree of finality for compliance with the CIP Standards NERCrsquos January 19 2010 Compliance Filing provides a description of NERCrsquos process for determining the scope of systems that must comply with the NERC CIP Standards and those systems that fall under the NRCrsquos regulations The Commission is not reviewing NERCrsquos scope of systems determination process itself ie the Bright-Line Test as the Commission in Order No 706-B left it to the ERO to formulate and implement an ldquoexceptions processrdquo33 Rather the Commission is evaluating whether NERCrsquos exemption process the scope of systems determination will unduly delay the date the CIP Standards become mandatory and enforceable for nuclear power plant licensees

30 Id at 4

31 Id

32 December 17 Order 129 FERC para 61224 at P 14

33 Order No 706-B 126 FERC para 61229 at P 50 (holding that with respect to the delineation of which balance of plant equipment may be subject to the NRC cyber security regulation ldquo[t]he Commission believes that with the above two-part approach ie subjecting all balance of plant equipment within a nuclear power plant to the CIP Reliability Standards with exceptions allowed via a process implemented by the ERO nuclear power plant licensees will have a bright-line rule that eliminates the potential regulatory gap and provides certainty and a plant-specific equipment exception process to avoid dual regulation where appropriaterdquo)

Docket No RM06-22-010 - 9 -

20 The Commission finds that NERCrsquos process for the scope of systems determination the Bright-Line Test along with NERCrsquos projected timeline for completing the Bright-Line Test provides for a final determination that will be made with a reasonable timeframe We note that while NERC states that it intends to finalize the scope of systems determination within eight months of the date the Implementation Plan becomes effective there remains the possibility that NERC will not meet that schedule NERC itself notes that the implementation schedule is ldquocontingent upon NRC resourcesrdquo34 For that reason the Commission remains concerned about potential delays in the compliance date Accordingly the Commission accepts NERCrsquos compliance filing and approves NERCrsquos Implementation Plan for US nuclear power plant ownersrsquo and operatorsrsquo compliance with Version 1 of the CIP Standards However should NERC become aware that it will be unable to complete the scope of systems determinations within NERCrsquos projected timeframe (R + 8 months) NERC must timely notify the Commission of the reason for the delay and propose an alternate deadline

21 Exelon requests that in recognition of the potential for delays in the scope of systems determination the Commission ldquocondition the effective date of its approval of NERCrsquos CIP Version 1 Implementation Plan for nuclear generator owners and operators based on the actual date that NERC and the NRC finalize the Bright-Line determinationrdquo35 The Commission finds that Exelonrsquos concern does not warrant action In the first instance NERC should meet the implementation schedule it has proposed and we approve in this order However as stated above NERC must notify the Commission give reason and propose an alternative deadline if it is unable to meet its projected timeframe of R + 8 months We believe this adequately resolves Exelonrsquos concern

22 Further Exelonrsquos request is unnecessary given the existing structure of the Implementation Plan As the Commission understands Exelonrsquos request Exelon wants the effective date of the Implementation Plan to be tied to the date NERC and the NRC complete the scope of systems determination The Implementation Plan is structured such that the compliance date is the latter of three scenarios one of which is tied to the date the scope of systems determination is completed Thus the CIP Standards will not become mandatory and enforceable against generator owners and operators of nuclear plants until at a minimum 10 months after the date NERC completes the scope of systems determination (designated as S + 10 months in the Implementation Plan) regardless of when the scope of systems determination is concluded Under this

34 Compliance Filing at 9-10

35 Exelon Comments at 4-5

Docket No RM06-22-010 - 10 -

structure if NERCrsquos scope of systems determination (ie completion of the Bright-Line test) is delayed the compliance deadline will also be delayed In other words NERCrsquos projected timeframe of R + 8 months36 for completing the scope of systems determination does not affect the amount of time licensees will have to become compliantwith the CIP

Standards

23 With respect to Exelonrsquos remaining concerns the Commission believes that they are beyond the scope of this order In this proceeding the Commission is ruling on the timeline of the proposed Implementation Plan and the adequacy by which it will ensure timely compliance with the CIP Standards The Commission has left the specific details of the development and implementation of the scope of systems determination to the discretion of the NRC and NERC

24 Last with respect to NERCrsquos request to submit after completion of its balloting process its compliance filing establishing implementation plans for Version 2 and Version 3 of the CIP Standards the Commission grants NERCrsquos request NERC is directed upon completion of its balloting process to make a compliance filing submitting implementation plans for the implementation of Versions 2 and 3 of the CIP Standards by owners and operators of US nuclear power plants on the same schedule established for Version 1 under the Implementation Plan

The Commission orders

(A) NERCrsquos compliance filing is hereby accepted as discussed in the body of this order

(B) NERCrsquos Implementation Plan governing ownersrsquo and operatorsrsquo of US nuclear power plants implementation of Version 1 of the CIP Standards CIP-002-1 through CIP-009-1 is hereby approved as discussed in the body of this order effective as of the date of this order

(C) NERC is hereby directed upon completion of its balloting process related to the implementation plans applicable to generator owners and operators of US nuclear power plants for Versions 2 and 3 of the CIP Standards to make a compliance filing submitting implementation plans for the implementation of Versions 2 and 3 of the CIP

36 ldquoRrdquo is the Commission-approved effective date of the Implementation Plan

Docket No RM06-22-010 - 11 -

Standards by owners and operators of US nuclear power plants on the same schedule established for Version 1 under the Implementation Plan as discussed in the body of this order

By the Commission ( S E A L )

Kimberly D Bose Secretary


6094528060 | wwwnerccom116-390 Village Boulevard Princeton New Jersey 08540-5721

Phone 6094528060 Fax 6094529550 wwwnerccom

Standard Authorization Request Form Title of Proposed Standard Project 2009-02 Real-time Reliability Monitoring and Analysis Capabilities

Original Request Date June 4 2009

Revised Date January 15 2010

Revised Date March 31 2010

SAR Requester Information SAR Type (Check a box for each one

that applies)

Name Jack Kerr New Standard(s) X

Primary Contact Dominion Virginia Power Revision to existing Standard X

Telephone 18042733393

Fax 18042732405

Withdrawal of existing Standard

E-mail jackkerrdomcom Urgent Action

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

The new or revised standard(s) will establish requirements for the functionality performance and change managementmaintenance of Real-time Monitoring and Analysis capabilities for Reliability Coordinators Transmission Operators Generator Operators and Balancing Authorities for use by their System Operators in support of reliable System operations


SARndash2


According to the Final Report on the August 14 2003 Blackout in the United States and Canada Causes and Recommendations dated April 2004 a principal cause of the August 14 blackout was a lack of situational awareness which was in turn the result of inadequate reliability tools In addition the failure of control computers and alarm systems incomplete tool sets and the failure to supply network analysis tools with correct System data on August 14 contributed directly to this lack of situational awareness Also the need for improved visualization capabilities over a wide geographic area has been a recurrent theme in blackout investigations

Recommendation 22 of the Blackout Report states ldquoEvaluate and adopt better real-time tools for operators and reliability coordinatorsrdquo NERCrsquos Operating Committee formed the Real-time Tools Best Practices Task Force (RTBPTF) to evaluate real-time tools and their usage within the industry The Task Force produced a report ldquoReal-Time Tools Survey

Analysis and Recommendationsrdquo dated March 13 2008 that included recommendations for the functionality performance and management of Real-time tools

There are 2 directives in FERC Order 693 relating to minimum tool capabilities that need to be addressed One directive pertains to IRO-002 and is described in paragraphs 905 amp 906 of Order 693 The second directive pertains to TOP-006 and is described in paragraph 1660 These directives clearly indicate the desire for a minimum set of capabilities as opposed to specific tools The existing projects that would have handled these issues (Project 2006-02 for IRO-002 and Project 2007-03 for TOP-006) have clearly indicated that they expect this SAR (Project 2009-02) to address the issues raised by FERC

This SAR addresses selected recommendations in the RTBPTF Report as determined by the Real-time Best Practices Standards Study Group Project 2009-02 and addresses the directives in Order 693 referenced above

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

The scope of the SAR is to establish requirements for the monitoring and analysis capabilities provided to System Operators and used to support Real-time System Operations The SAR addresses availability parameters performance metrics and procedures for failure notification maintenance coordination and change management The intent is to describe lsquowhatrsquo needs to be done but not lsquohowrsquo to do it

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

Develop or revise standard(s) to describe the capability characteristics such as availability parameters performance metrics and procedures for failure notification and maintenance


SARndash3

coordination and change management (vetted by the industry through the Reliability Standards comment process)of functionality for

bull bull Monitoring power System data in Real-time

bull Exchanging power System data in Real-time

bull Emitting Real-time visible and audible signals to aAlerting System Operators in Real-time to events and conditions affecting the state of the Bulk Electric System (BES) This functionality shall include an independent process monitor (eg watchdog)

bull Determining the current state of the BES

bullEvaluating the impact of lsquowhat ifrsquo events on the current or future state of the BES

bull


SARndash4


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

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

Reliability Coordinator

X 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 gtone year plan for the resource adequacy of its specific loads within a Planning Coordinator area

Transmission Planner

Develops a gtone year plan for the reliability of the interconnected Bulk Electric System within its portion of the Planning Coordinator area


Administers the transmission tariff and provides transmission services under applicable transmission service agreements (eg the pro forma tariff)

Transmission Owner

Owns and maintains transmission facilities

X Transmission Operator

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

Distribution Provider

Delivers electrical energy to the End-use customer

Generator Owner

Owns and maintains generation facilities

X Generator Operator

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

Purchasing-Selling Entity

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

Market Operator

Interface point for reliability functions with commercial functions

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

Load-Serving Entity


SARndash5



Reliability and Market Interface Principles

Applicable Reliability Principles (Check box for all that apply)

1 X 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 X 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 X

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 X

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 X

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

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

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

1

(Select lsquoyesrsquo or lsquonorsquo from the drop-down box)

2

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

3

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

4

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


Standards Authorization Request

7

Related Standards


TOP-xxx The TOP family of standards is undergoing revision The eventual SDT should have the flexibility to revise these standards or write new standards as best fits the task

IRO-xxx The IRO family of standards is undergoing revision The eventual SDT should have the flexibility to revise these standards or write new standards as best fits the task

COM-001-11 The eventual SDT should have the flexibility to revise this standard or write new standards as best fits the task

BAL-xxx

The BAL family of standards should be included in the scope of this SAR because they do address reliability-based data Therefore the eventual SDT should have the flexibility to revise these standards or write new standards as best fits the task

Related SARs


Regional Variances

Region Explanation

ERCOT

FRCC

MRO

NPCC

SERC

RFC

SPP

WECC

Concept White Paper Concepts for Proposed Content of Eventual Standard(s) for Project 2009-02 Real-Time Monitoring and Analysis Capabilities

Real-time Monitoring and Analysis Capabilities Standard Drafting Team February 15 2011

2 of 9

10

INTRODUCTION

FERC Order 693 indicates the need for a minimum set of capabilities to be available for System Operators to assist in making Real-time decisions The work done by the Real-time Tools Best Practices Task Force (RTBPTF) which was formed by NERC in response to the Final Report on the August 14 2003 Blackout in the United States and Canada Causes and Recommendations is the basis for the Real-time Monitoring and Analysis Capabilities SAR that was approved by the Standards Committee in April 2010 and the subsequent appointment by NERC of a Standard Drafting Team (RMACSDT) to develop a standard to satisfy the proposed issues described in the SAR utilizing the results-based standards methodology This White Paper is a description of the present thinking of the RMACSDT regarding standard requirements for Real-time monitoring and analysis capabilities The paper consists of four sections that describe the major areas proposed to be addressed by the eventual standard(s) These areas are Section 2 - Monitoring Section 3 - Data exchange Section 4 - Alarming Section 5 ndash Analysis

The SDT will also be crafting an Implementation Plan for any eventual standard(s) that will be vetted by the industry through comments and that will allow for sufficient time for applicable entities to bring their systems into compliance with any new requirements

20

MONITORING

Monitoring is the first component in the process of establishing situational awareness for the System Operators so that they can rapidly assess the state of the Bulk Electric System (BES) In the context of this standard ldquomonitoringrdquo implies System Operators viewing data in a manner that allows them to determine the state of the BES in Real-time and to take corrective and preventive actions when necessary The types of data to be considered by the standard are Real-time analog and status

o Scanned o Calculated

For purposes of monitoring as described in this paper this is data scanned by a central system from Data Collection Units (DCU) such as Remote Terminal Units (RTUs) Calculated values are treated the same as scanned values in this paper It is proposed that requirements for monitoring will be applicable to Reliability Coordinators Transmission Operators and Balancing Authorities

3 of 9

The following requirements are proposed for monitoring of Real-time data These requirements assume that the Responsible Entity is utilizing an Energy Management System (EMS) andor Supervisory Control and Data Acquisition (SCADA) system to collect the Real-time data

21 PERFORMANCE A performance parameter is proposed for each category of data collected and the data displayed to the operator

211 Status Data Status data shall be collected at a scan rate not to exceed 4 seconds

212 Analog Data In many systems analog data is collected at multiple scan rates depending on the applications in which the data is being used It is proposed that all analog data except the data identified in the BAL standards is scanned at a rate not to exceed 10 seconds - the rate suggested in the RTBPTF report

213 Data Display All active displays utilized for visualization of the data discussed above shall update by the end of the next status or analog scan cycle as stated above following the scan in which the data was received by the central system For example status data should be updated within 4 seconds following the receipt of the scan by the central system

22 AVAILABILITY The SDT proposes two requirements for availability A demonstrable procedure shall be developed describing the alternate plans andor

mitigating measures entities have in place when the data used to monitor BES or perform analyses on BES (see Section 5) becomes unavailable

For each DCU availability shall be calculated by dividing the number of ldquogoodrdquo scans

received at the central system by the number of scans scheduled to be received in a calendar month (A lsquogoodrsquo scan is a complete packet of requested data returned to the central system) The ratio of scans received to scans scheduled shall exceed 99 for a

4 of 9

calendar month This calculation can include alternate or backup data sources that provide data when the primary DCU is unavailable

23 FAILURE NOTIFICATION lsquoFailurersquo is assumed to occur when a scan is not completed for any reason and it shall be notified after the 9th consecutive lsquofailurersquo occurs The System Operator shall be notified of such failure within 60 seconds of the 9th

consecutive lsquofailurersquo

24 MAINTENANCE Each Responsible Entity shall provide the System Operator with approval authority for planned maintenance that impact monitoring capabilities

30

DATA EXCHANGE

Data exchange as discussed in this paper refers to electronic exchange of data between two computer based control systems (EMS andor SCADA) whether they are internal or external to each other It is assumed that the data links discussed will utilize ICCP or an equivalent protocol Data exchange in this context does not include RTUs or other similar types of DCUs Required data sets to be exchanged are covered in proposed IRO-010-2 and TOP-003-2 ICCP is the Inter-Control Center Communications Protocol (ICCP or IEC 60870-6TASE2 or latest release) It is an international standard used by utility organizations to provide data exchange over wide area networks (WANs) between utility control centers utilities power pools regional control centers and Non-Utility Generators Collecting and exchanging real-time data on power system status is one of the elementary steps in the complex process of developing the information that System Operators need to maintain situational awareness Real-time reliability tools such as the state estimator and contingency analysis can only provide results that accurately represent current and potential reliability problems if these tools have Real-time analog and status data The accuracy of the information that Real-time reliability tools provide depends on the accuracy of the data supplied to the tools The quality of the results that Real-time reliability tools produce is also influenced by the breadth and depth of the portion of the BES for which Real-time data are collected relative to the breadth and depth of the relevant Reliability Entityrsquos area of responsibility It is proposed that requirements for data exchange will be applicable to the Reliability Coordinator Transmission Operator Balancing Authority and Generation Operator

5 of 9

The following requirements are proposed for data exchange of Real-time data These requirements assume that the Responsible Entity is utilizing an EMS andor SCADA system utilizing ICCP or an equivalent protocol to exchange data

31 PERFORMANCE The SDT proposes the following requirements for data exchange performance ICCP (or equivalent) data exchange must be redundant and the redundancy must be

supplied through diverse routing

Entities shall develop data exchange agreements and comply with data specifications Data exchange agreements must include the following

bull Interoperability of ICCP and equivalent systems bull Data access restrictions bull Data naming conventions bull Data management and coordination including data quality bull Joint testing and data checkout bull Monitoring of availability bull Responsibility for failures bull Restoration process

32 AVAILABILITY The SDT proposes the following requirements for data exchange availability Establish procedure for actions to be taken if some or all of the data exchanged is not

available for a 30 minute timeframe

33 FAILURE NOTIFICATION Notification of link failure must be made to the System Operator within 60 seconds of when link failure occurred Failure is identified as the inability to receive a complete data set regardless of reason

34 MAINTENANCE Each functional entity shall provide System Operators with approval authority for planned maintenance of its data exchange capabilities Coordination with affected entities is required

6 of 9

40

ALARMING

Alarms must be generated to alert System Operators in Real-time to events and conditions affecting the state of the BES Alarms can be audible andor visual Alarms must be generated for the following reasons

bull Limit violations (for any defined limits including multiple limits on a single point)

bull Uncommanded status changes bull DCU unavailability bull Data exchange link unavailability

Alarms are important to the safe and secure operation of the BES System Operators depend on alarms to identify problems occurring or about to occur All values measured or calculated by the EMS andor SCADA must be subject to processing to determine either change of state or limit violations If either of these conditions occurs an alarm must be generated It is proposed that requirements for alarming will be applicable to Reliability Coordinators Transmission Operators and Balancing Authorities The following requirements are proposed for alarming of measured and calculated data

41 PERFORMANCE Performance issues such as volume and throughput of alarms are recognized as potential concerns but are generally handled in initial EMSSCADA vendor specifications It would be difficult if not impossible to measure in a production system Therefore no performance requirement is anticipated as part of this project

42 AVAILABILITY The SDT proposes the following requirements for alarming availability

bull No specific numeric value will be proposed for alarming availability bull Establish a procedure for actions to be taken when the alarming functionality is

unavailable for 10 consecutive minutes (see RTBPTF report page 117 paragraph 4) For example the Reliability Coordinator lsquobacks uprsquo the Transmission OperatorBalancing Authority and vice versa and entities inform each other of failure of their alarming capability

7 of 9

43 FAILURE NOTIFICATION Notification of failure of the alarm processing function must be made to the System Operator within 60 seconds of when failure is detected Notification of failure of alarming capability must be accomplished through independent failure notification where the system creating and presenting the notification is independent of the alarming functionality

44 MAINTENANCE Each functional entity shall provide System Operators with approval authority for planned maintenance of its alarming capabilities

50

ANALYSIS

The intent of analysis in the context of this white paper is to focus on determining the current condition or state of the BES and evaluate the impact of lsquowhat ifrsquo events on the state of the BES The meanings of ldquocurrentrdquo and ldquowhat-ifrdquo are

bull Current - The current system condition or state is a function of the most recent system bus voltages system topology frequency and line flows

bull lsquoWhat ifrsquo - Analyze the impact on the security of the current power system state of

specific Contingencies or simulated outages of the BES such as lines generators or other equipment This analysis should also include other system condition changes that would affect the BES such as Load The analysis identifies problems such as line overloads or voltage violations that will occur if the system event or Contingency takes place

The capability to determine the current state of the BES is critical for the System Operator to determine violations of reliability criteria in their area By accurately determining the current state of the BES the System Operator is thus capable of evaluating various lsquowhat ifrsquo scenarios Having the results of the lsquowhat ifrsquo events before they happen allows System Operators to take the appropriate actions to prevent violations or have plans ready if such Contingencies were to occur It is proposed that requirements for analysis will be applicable to the Reliability Coordinator and Transmission Operator The following requirements are proposed for analysis of the current and ldquowhat-ifrdquo states of the BES

8 of 9

51 PERFORMANCE The requirements for Performance will address periodicity and quality

511 Periodicity The current and ldquowhat-ifrdquo analyses shall run based on the following conditions

bull Current analysis - Automated program required that runs periodically at no more than a 5 minute interval to determine the systemrsquos current condition or state The analysis may be either a program that runs on the Reliability Coordinatorrsquos or Transmission Operatorrsquos EMS or through contracted services (3rd


bull ldquoWhat ifrdquo analysis - Automated program required that runs periodically at no more than a 10 minute interval (from pg 117 of Blackout Report - 4b) to analyze the impact on the security of the current power system state for specific Contingencies or simulated outages of the BES such as lines generators or other equipment The analysis may be either a program that runs on the Reliability Coordinatorrsquos or Transmission Operatorrsquos EMS or through contracted services (3rd


512 Results Quality

Quality needs to be measured to ensure that the base case used by the automated analysis program(s) accurately represent the state of the system

bull For both current amp ldquowhat ifrdquo analyses

o For Reliability Coordinator amp Transmission Operator

o Compare physical lsquotiersquo line values and generator injections plus selected interconnected transmission line flows from the automated analysis program(s) to actual metered values every time the program runs These values have been selected because of the accuracy of the metering at those locations and their impact on the BES

o Compute the percentage deviation of the program values versus actual metered values

o Compute the average of the percentages on a periodic basis and compare to the tolerance value (Actual periodicity will be selected based on industry feedback)

o Tolerance must be +- x (Actual value will be selected based on industry feedback)

9 of 9

52 AVAILIBILITY Responsible entities must establish a procedure for what to do if the program(s) is not available for more than 30 consecutive minutes Current - The automated programs must provide a solution every five minutes 99 of the time on a monthly basis lsquoWhat ifrsquo - The automated programs must provide a solution every ten minutes 99 of the time on a monthly basis

53 FAILURE NOTIFICATION Notification of failure of the analysis capability to provide a solution to the System Operator must be made to the System Operator within 60 seconds of when failure is detected

54 MAINTENANCE Each functional entity shall provide System Operators with approval rights for planned maintenance of its analysis capabilities

From scottvidlerHydroOnecomTo Lee R PedowiczSubject RE RSC Meeting--March 16-17 2011Date Monday February 28 2011 25358 PM

Hi LeeEven though we posted the white paper to solicit industry feedback so that we couldconsider them in the drafting of the standard we donrsquot expect the project to continue at thistime NERC has performed an analysis of the outstanding standards that are in the hopperand used a prioritizing method to attempt to get the most important standards movingtowards completion At this time the Real-time Reliability Monitoring and AnalysisCapabilities standard is not going to make this yearrsquos active project list We will collect thedata from the white paper and the team members will be able to use it to guide any of ourdiscussions and when we reconvene hopefully we will be able to come out of the blocksand do a 100 metre dash to the finishI can certainly join a conference call ndash but there will not be much to say Irsquom available onMarch 17RegardsScott VidlerManager - Grid OperationsOperating Performance amp Customer SupportOntario Grid Control CentreHydro One Networks IncPhone 7057923020Cell 7056271436Internet scottvidlerhydroonecomGood ideas are not adopted automatically They must be driven into practice with courageous patience mdash HymanRickoverldquoThis e-mail and any attached files are privileged and may contain confidential information intended only for the person or personsnamed above Any other distribution reproduction copying disclosure or other dissemination is strictly prohibited If you havereceived this e-mail in error please notify the sender immediately by reply e-mail and delete the transmission received by yourdquo

From Lee R Pedowicz [mailtolpedowicznpccorg] Sent Monday February 28 2011 100 PMTo VIDLER ScottCc Guy V Zito Gerard J DunbarSubject RSC Meeting--March 16-17 2011 Good afternoon Scott At our upcoming NPCC RSC Meeting March 16-17 2011 we discuss the NERC Standards that areposted for comment or under development I checked our information and it lists you as being amember of the Drafting Team for Project 2009-02 - Real-time Reliability Monitoring and AnalysisCapabilities Being that it will still be posted when we have our meeting would you be able to callin and give us a summary of its status Our meeting is from 1000 am until 500 pm March 16and then 800 am until 300 pm on March 17 Wersquoll arrange our agenda for you Thanks

Lee PedowiczManager Reliability StandardsNPCCThis email and any of its attachments may contain information that is privilegedconfidential classified as CEII or subject to copyright belonging to NPCC This email isintended solely for the use of the individual or entity to which it is addressed If you are notthe intended recipient of this email you are hereby notified that any disseminationdistribution copying or action taken in relation to the contents of and attachments to thisemail is strictly prohibited and may be unlawful If you receive this email in error pleasenotify the sender immediately and permanently delete the original and any copy of this emailand any printout

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Informal Comment Period Open - Project 2009-02 Real-time Monitoring and Analysis CapabilitiesDate Wednesday February 16 2011 30000 PM

Standards AnnouncementProject 2009-02 Real-time Monitoring and Analysis CapabilitiesInformal Comment Period OpenFebruary 16 ndash April 4 2011 Now available at httpwwwnerccomfilezstandardsProject2009-02_Real-Time_Monitoring_Analysis_Capabilitieshtml Informal Comment Period Open through 8 pm on Monday April 4 2011The Project 2009-02 Real-time Monitoring and Analysis Capabilities Standard Drafting Team has posted for a 45-day informal commentperiod a White Paper on proposed concepts to support the development of real-time monitoring and analysis standards The White Paperalong with an unofficial Word version of the comment form have been posted on the project Web page athttpwwwnerccomfilezstandardsProject2009-02_Real-Time_Monitoring_Analysis_Capabilitieshtml InstructionsPlease submit comments using the electronic form Next StepsThe drafting team will consider the input received on the concept White Paper as it begins preparing to draft standards Project BackgroundThe need for improved visualization capabilities over a wide geographic area has been a recurrent theme in blackout investigationsAccording to the Final Report on the August 14 2003 Blackout in the United States and Canada Causes and Recommendations dated April2004 a principal cause of the August 2003 blackout was a lack of situational awareness a result of inadequate reliability tools NERCrsquos Operating Committee formed the Real-time Tools Best Practices Task Force (RTBPTF) to evaluate real-time tools and their usagewithin the industry The Task Force produced a report ldquoReal-Time Tools Survey Analysis and Recommendationsrdquo dated March 13 2008that included recommendations for the functionality performance and management of real-time tools This project addresses recommendations from the August 2003 Blackout Report the RTBPTF report and two directives from FERC Order693 Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate

For more information or assistance please contact Monica Benson at monicabensonnercnet




---You have received this email because you are a registered representative in the Registered Ballot Body

From Elizabeth HeenanTo Elizabeth HeenanSubject Comment Period Opens for Proposed Changes to ReliabilityFirst Corporation Rules of Procedure Pertaining to Regional Standards Development ProcessDate Tuesday March 01 2011 63525 PM

Comment Period Opens for Proposed Changes to ReliabilityFirstCorporationrsquos Rules of Procedure ndash Regional Standards DevelopmentProcess NERC Stakeholders Now available at httpwwwnerccomfilesFinal_Posting_RFC_Standards_Process_Changes_20110301pdf

NERC requests comments on the proposed revisions to ReliabilityFirst Corporationrsquos reliability standards development procedure OnJanuary 14 2011 NERC received a request from ReliabilityFirst Corporation to modify its proposed regional standard developmentprocess changes approved by the ReliabilityFirst Corporation Board of Directors In accordance with Section 311 of the NERC Rules of Procedure NERC is required to publicly notice and request comment on anyproposed changes to a regional standards development procedure for a minimum 45-day comment period Any objections identified bystakeholders during the posting period shall be resolved by ReliabilityFirst Corporation before the proposed changes are presented to theNERC Board of Trustees for approval Upon NERC Board of Trustee approval NERC shall file the proposed changes pursuant to 18 CFRsect 3910 (2010) with the Federal Energy Regulatory Commission for approval Materials Included in this Request for Comments

Letter from Timothy R Gallagher to David Cook outlining process and changes Attachment A- ReliabilityFirst Corporation Reliability Standards Development Procedure ndashVersion 3 (Clean) Attachment B - ReliabilityFirst Corporation Reliability Standards Development Procedure ndashVersion 3 (Redline) and Attachment C ndash Corresponding changes to Exhibit C to ReliabilityFirst Regional Delegation Agreement (Redline)

Comments are due April 15 2011 and must be submitted electronically to ropcommentsnercnet




6094528060 | wwwnerccom ---You are currently subscribed to nerc-info as lpedowicznpccorgTo unsubscribe send a blank email to leave-1249731-3256541ca6f85fb1574a8515cc07df72d3bfe0listservnerccom



Notice of Proposed Changes to RFC Rules of Procedure and Request for Comments

Proposed Changes to ReliabilityFirst Corporation Rules of Procedure Comments Due April 15 2011 The North American Electric Reliability Corporation (ldquoNERCrsquo) hereby requests comments on the proposed revisions to ReliabilityFirst Corporationrsquos reliability standards development procedure On January 14 2011 NERC received a request from ReliabilityFirst Corporation to modify its proposed regional standard development process changes approved by the ReliabilityFirst Corporation Board of Directors NERC has determined that ReliabilityFirst Corporationrsquos proposed regional reliability standards development procedure meets the criteria included in Section 31131 of the NERC Rules of Procedure (open inclusive balanced due process and transparent) In accordance with Section 311 of the NERC Rules of Procedure NERC is required to publicly notice and request comment on any proposed changes to a regional standards development procedure for a minimum 45-day comment period Any objections identified by stakeholders during the posting period shall be resolved by ReliabilityFirst Corporation before the proposed changes are presented to the NERC Board of Trustees for approval Upon NERC Board of Trustee approval NERC shall file the proposed changes pursuant to 18 CFR sect 3910 (2010) with the Federal Energy Regulatory Commission for approval

Materials Included in this Request for Comments

- Letter from Timothy R Gallagher to David Cook outlining process and changes - Attachment A- ReliabilityFirst Corporation Reliability Standards Development Procedure ndashVersion 3

(Clean) - Attachment B - ReliabilityFirst Corporation Reliability Standards Development Procedure ndashVersion

3 (Redline) and - Attachment C ndash Corresponding changes to Exhibit C to ReliabilityFirst Regional Delegation

Agreement (Redline) Submission of Comments Comments are due April 15 2011 and must be submitted electronically to ropcommentsnercnet NERC intends to submit the proposed changes to the ReliabilityFirst standards development procedure to the NERC Board of Trustees for approval at its May 11 2011 meeting For further information please contact Elizabeth Heenan at elizabethheenannercnet


January 14 2011 Mr David Cook Senior Vice President and General Counsel North American Electric Reliability Corporation Princeton Forrestal Village 116-390 Village Boulevard Princeton NJ 08540-5721 Dear David Please find attached to this letter the revised Standards Development Procedure (the ldquoProcedurerdquo) of ReliabilityFirst Corporation (ldquoReliabilityFirstrdquo) reflecting revisions to the Procedure approved by the Board of Directors of ReliabilityFirst on December 15 2010 (Attachments A and Bmdashclean and redlined versions) and a redline version of Exhibit C (Attachment C) to the Regional Delegation Agreement (ldquoRDArdquo) The redline Exhibit C is included to demonstrate that the revisions to the Procedure continue to adhere to the Attributes specified in Exhibit C for the development of Regional Reliability Standards ReliabilityFirst revised the Procedure to improve the openness of the process to increase the requirement on affirmative votes to align with the North American Electric Reliability Corporation (ldquoNERCrdquo) process to better align the ReliabilityFirst process with the NERC process and to improve clarity and understanding of the process With this filing ReliabilityFirst seeks to satisfy the requirements of the Federal Energy Regulatory Commissionrsquos (ldquoFERCrdquo or the ldquoCommissionrdquo) regulations regarding changes to Regional Entity Rules As specified in 18 CFR sect 391 (2010) the Standards Development Procedure of a Regional Entity such as ReliabilityFirst are Regional Entity Rules As such the Commissionrsquos regulations require that NERC as the Electric Reliability Organization must approve any modifications or revisions to the Procedure and then submit any approved modifications or revisions to the Commission for approval 18 CFR sect 3910 (2010) and North American Electric Reliability Council et al 119 FERC para 61060 at P 333 (2007) The Commissionrsquos regulations require that when NERC submits changes in Regional Entity Rules to the Commission NERC must explain ldquothe basis and purpose for the Rule or Rule change together with a description of the proceedings conducted by the Regional Entity to develop the proposalrdquo 18 CFR sect 3910 (2010) To assist NERC in complying with this requirement and to aid NERC in its independent consideration of the revisions to the Procedure ReliabilityFirst is supplying the information requested by the regulations

Timothy R GallagherPresident and Chief Executive Officer

Direct Dial (330) 247-3040timgallagherrfirstorg

2

I The Basis and Purpose for the Revisions to the Procedure

A Substantive Revisions The revised Procedure contains the following substantive revisions

1 Include an informal Standard Authorization Request (ldquoSARrdquo) comment period step

a Added a SAR comment step to assist the ReliabilityFirst Standards Committee (ldquoSCrdquo) in determining if the SAR should move into the standard drafting phase

2 Make the Category Ballot approval percentage consistent with NERC (super-majority

vs simple majority

a Changed the approval percentage to two-thirds or greater

3 Modifications to the voting and Ballot Pool structure

a Modified the voting and Ballot Pool structure to further align with the NERC process

b Corporations or organizations will be able to cast one vote in each ReliabilityFirst registered voting category as long as a different individual is registered in each registered voting category If a corporation or organization is registered in each one of the ReliabilityFirst voting categories the maximum number of votes possible is five including corporation and organization affiliates

4 Inclusion of a Recirculation Ballot period

a A Recirculation Ballot period will be required if ReliabilityFirst received any negative ballot comments during the initial 15-Day Category Ballot

b The addition of a recirculation ballot will give stakeholders the opportunity to review the comments submitted by other entities during the initial Category Ballot to determine if they wish to reconsider their voting position

5 Inclusion of an informal comment period within the Interpretation section

a Added an informal comment period to the Interpretation section which will increase the transparency of the Procedure and allow stakeholders to weigh in on interpretations developed by ReliabilityFirst

6 Inclusion of language referencing the use of the NERC Standards Template

a Added additional language referencing the use of NERC Standards Template to allow ReliabilityFirst standards and NERC standards to follow a consistent format and template


7 Further clarification regarding ldquoEffective Datesrdquo

a Added language to further clarify ldquoEffective Datesrdquo for ReliabilityFirst standards

i ReliabilityFirst standards are mandatory and enforceable without monetary penalties for non-compliance upon the effective date for applicable entities that are members of ReliabilityFirst

ii ReliabilityFirst standards are mandatory and enforceable with monetary penalties for non-compliance for all applicable registered entities within the ReliabilityFirst footprint upon approval by the Commission

B Changes to Correct TypographicalTechnical Issues The revised Procedure contains the following minor revisions

8 Removal of references to the ldquoInterim Compliance Committee (ldquoICCrdquo) from the Interpretation section since the ICC no longer exists

9 A number of format and editorial changes to further clarify certain sections II Proceedings Conducted by ReliabilityFirst to Revise the Procedure

ReliabilityFirst followed the current FERC-approved Standards Development procedure to develop the revisions submitted with this filing See 119 FERC para 61060 at P 339 Specifically on January 20 2010 the SC authorized a SAR to modify two specific items of the Procedure The scope of the SAR consisted of items 1 and 2 above On April 30 2010 the SC authorized a supplemental SAR (based on the recommendation of the ReliabilityFirst Standard Drafting Team) in which the scope consisted of the remaining items identified above Upon completion of the items listed in the two SARs ReliabilityFirst posted the revised Standards Procedure for one 30-Day Comment period (June 16 2010 through July 15 2010) in which a total of 17 commenters provided comments After responding to all comments and modifying the Procedure accordingly ReliabilityFirst posted the Procedure for the required 15-Day period prior to Category Ballot (August 17 2010 through August 31 2010) followed by the 15-Day Category Ballot (September 1 2010 through September 15 2010)

The Procedure passed the 15-Day Category Ballot achieving quorum (972) with an overwhelming affirmative category vote (100) Following the Category Ballot the Procedure was publically posted for the required 30 days prior to ReliabilityFirst Board action (September 24 2010 through October 23 2010) The ReliabilityFirst Board of Directors unanimously approved the Procedure on December 15 2010

4

III Conclusion ReliabilityFirst believes these revisions do not affect its delegated authority under 18 CFR sect 398 ReliabilityFirst respectfully requests that NERC consider and approve the foregoing amendments to the ReliabilityFirst Standards Development Procedure and submit the revised Procedure to the Commission for its approval as changes to the rules of a Regional Entity in accordance with 18 CFR sect 3910

Sincerely RELIABILITYFIRST CORPORATION Timothy R Gallagher President and Chief Executive Officer

cc Susan O Ivey ReliabilityFirst Corporation Chair Board of Directors Kenneth Defontes ReliabilityFirst Corporation Vice-Chair Board of Directors Larry E Bugh ReliabilityFirst Corporation Director of Corporate Affairs L Jason Blake ReliabilityFirst Corporation Corporate Counsel Anthony E Jablonski ReliabilityFirst Corporation Standard Process Manager

Attachment A ReliabilityFirst Standards Development Procedure


(Clean)


Procedure Version 3




Table of Contents

Introduction 1 Background 2 Regional Reliability Standard Definition Characteristics and Elements 3 Roles in the Regional Reliability Standards Development Process 7 Regional Reliability Standards Development Process 8 Appendix A Maintenance of Regional Reliability Standards Development Processhelliphelliphellip17 Appendix B Standard Authorization Request 21 Appendix C Flowchart for Standards Process 28 Appendix D Ballot Pool Categories and Registration 30


Introduction This procedure establishes the process for adoption of a Regional Reliability Standard1 (hereinafter referred to as ldquoStandardrdquo) of the ReliabilityFirst Corporation (ReliabilityFirst) and the development of consensus for adoption approval revision reaffirmation and deletion of such Standards1 ReliabilityFirst Standards provide for the reliable regional and sub-regional planning and operation of the Bulk Power System2 (BPS) consistent with Good Utility Practice2 within the ReliabilityFirst geographical footprint This procedure was developed under the direction of the ReliabilityFirst Board of Directors (Board) who may request changes to this ReliabilityFirst Reliability Standards Development Procedure (hereinafter referred to as ldquothis Procedurerdquo) as deemed appropriate A procedure for revising this Procedure is contained in Appendix A This Procedure is consistent with the North American Electric Reliability Corporation (NERC) Reliability Standards Development Procedure ReliabilityFirst standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA The approval date of each ReliabilityFirst standard is upon ReliabilityFirst Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 The ReliabilityFirst standard is mandatory and enforceable (with monetary penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint upon approval by FERC The effective date for non-members upon the FERC approval will be determined by the implementation plan that is provided with each new or revised standard ReliabilityFirst Standards shall provide for as much uniformity as possible with NERC reliability standards across the interconnected BPS A ReliabilityFirst Standard shall be more stringent than a NERC reliability standard including a regional difference that addresses matters that the NERC reliability standard does not or shall be a regional 1 Legacy standards such as ECAR Documents MAIN Guides and MAAC Procedures shall be considered ReliabilityFirst Regional Reliability Standards for the purposes of this document until otherwise acted upon by the ReliabilityFirst Board 2 As defined in the ReliabilityFirst By-laws 3 By applying for and becoming a Regular or Associate Member of the Corporation each Member agrees to comply with all Reliability Standards all NERC standards and requirements and the other obligations of Members of the Corporation set forth in the ReliabilityFirst Bylaws or duly adopted by the Board in order to achieve the purposes of the Corporation


difference necessitated by a physical difference in the BPS A ReliabilityFirst Standard that satisfies the statutory and regulatory criteria for approval of proposed NERC reliability standards and that is more stringent than a NERC reliability standard would generally be acceptable ReliabilityFirst Standards when approved by FERC shall be made part of the body of NERC reliability standards and shall be enforced upon all applicable BPS owners operators and users within the ReliabilityFirst area regardless of membership in the region Background Regions may develop through their own processes separate ldquoRegional Standardsrdquo (ReliabilityFirst Standards) that go beyond add detail to or aid implementation of NERC reliability standards or otherwise address issues that are not addressed in NERC reliability standards As a condition of ReliabilityFirst membership all ReliabilityFirst Members2 agree to adhere to the NERC reliability standards As such the ReliabilityFirst and its Members will adhere to the NERC reliability standards in addition to the ReliabilityFirst Standards NERC reliability standards and the ReliabilityFirst Standards are both to be included within the ReliabilityFirst Compliance Program









As contained in the ReliabilityFirst By-laws ReliabilityFirst ldquoRegional Reliability Standardrdquo shall mean a type of Reliability Standard that is applicable only within a particular Regional Entity or group of Regional Entities A Regional Reliability Standard may augment add detail to or implement another Reliability Standard or cover matters not addressed by other Reliability Standards Regional Reliability Standards upon adoption by NERC and approval by the Commission enforced within the applicable Regional Entity or Regional Entities pursuant to delegated authorities Inherent in this definition a ReliabilityFirst Standard will define certain obligations or requirements of entities that own operate plan and use the BPS within the ReliabilityFirst geographical footprint These obligations or requirements as contained in the ReliabilityFirst Standards are to be measurable and consistent with Good Utility Practice Standards are not to include processes or procedures that implement a Standard In addition obligations requirements or procedures imposed upon ReliabilityFirst by NERC reliability standards are not to be ReliabilityFirst Standards unless those obligations requirements or procedures require the establishment of a ldquopolicy or standardrdquo as defined by the ReliabilityFirst By-laws Characteristics of a Regional Reliability Standard A Standard is policy including adequacy criteria to provide for the reliable regional and sub-regional planning and operation of the BPS consistent with Good Utility Practice A Standard shall generally have the following characteristics




Format Requirements of a Regional Reliability Standard A Standard shall consist of the requirements shown in the Regional Reliability Standard Template These requirements apply to the development and revision of Standards These requirements are necessary to achieve Standards that are measurable enforceable and consistent Supporting documents to aid in the implementation of a Standard may be referenced by the Standard but are not part of the Standard itself The most current version of the approved NERC Reliability Standard template and its associated elements


posted on the NERC website will be used at the time of the development of a ReliabilityFirst Regional Reliability Standard if different from the elements listed below








Requirement(s) Explicitly stated technical performance and preparedness requirements Each requirement identifies what entity is responsible and what action is to be performed or what outcome is to be achieved Compliance is mandatory for each statement in the requirements section


Risk Factor(s)


Measure(s) Each requirement shall be addressed by one or more measurements that will be used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measurement identifies to whom the measurement applies Each measurement shall be tangible and as objective as is practical Achieving the full compliance level of each measurement is a necessary and sufficient indicator that the requirement was met






for measuring performance or outcomes bull The process that will be used to evaluate information for the

purpose of assessing performance or outcomes bull The entity that is responsible for evaluating information to assess

performance or outcomes bull The time period in which performance or outcomes is measured

evaluated and then reset bull Data retention requirements and assignment of responsibility for

data archiving bull Violation severity levels





Each ReliabilityFirst Standard shall have an associated implementation plan describing the effective date of the Standard or effective dates if there is a phased implementation The implementation plan may also describe the implementation of the Standard in the compliance program and other considerations in the initial use of the Standard such as necessary tools training etc The implementation plan must be posted for at least one public comment period and be approved as part of the ballot of the standard


This section references related documents that support reasons for or provide additional information related to the Standard Examples include but are not limited to bull Glossary of Terms bull Developmental history of the Standard and prior versions bull Subcommittee(s) responsible for Standard bull Notes pertaining to implementation or compliance bull Standard references bull ProceduresPractices bull Training andor Technical Reference



will advise the ReliabilityFirst Board on Standards presented for adoption by the ReliabilityFirst Board Standards Process Manager (SPM) ndash A person or persons on the ReliabilityFirst staff assigned the task of ensuring that the development revision or deletion of Standards is in accordance with this Procedure The SPM works to ensure the integrity of the process and consistency of quality and completeness of the Standards The SPM facilitates the administration of all actions contained in all steps in the process Standards Process Staff ndash Employees of the ReliabilityFirst that work with or for the SPM Standard Drafting Team (SDT) ndash A team of technical experts and typically including a member of the ReliabilityFirst Standards staff and the Originator assigned the task of developing a proposed Standard based upon an approved SAR using the Standard development process contained in this Procedure Ballot Body (BB) ndash The Ballot Body comprises all entities that qualify for one or more of the categories and are registered with ReliabilityFirst as potential ballot participants in the voting on standards The categories of registration within the Ballot Body and the registration process are described in Appendix D Ballot Pool ndash The Ballot Pool is comprised of those members of the Ballot Body that register to vote for each particular standard A separate Ballot Pool is established for each standard up for vote Only individuals who have joined the Ballot Pool for that particular standard are eligible to vote on a standard Reliability Committee (RC) ndash The ReliabilityFirst RC serves as a technical advisory body to address the reliability related activities required by the Reliability Standards via review and discussion of the regional activities as requested by the SC Regional Reliability Standard Development Process (Flow chart of Process shown in Appendix C) Assumptions and Prerequisites The ReliabilityFirst Regional Reliability Standards Development Process has the following characteristics



bull Openness - Participation is open to all Organizations who are directly and materially affected by the ReliabilityFirst region BPS reliability There shall be no undue financial barriers to participation Participation shall not be conditioned upon membership in the ReliabilityFirst and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements Meetings of SDTs are open to the ReliabilityFirst membership and to others









Each standard shall enable or support one or more of the reliability principles thereby ensuring that each standard serves a purpose in support of the reliability of the regional BPS Each standard shall also be consistent with all of the reliability principles thereby ensuring that no standard undermines reliability through an unintended consequence While ReliabilityFirst Standards are intended to promote reliability they must at the same time accommodate competitive electricity markets Reliability is a necessity for electricity markets and robust electricity markets can support reliability Recognizing that BPS reliability and electricity markets are inseparable and mutually interdependent all ReliabilityFirst Standards shall be consistent with NERCrsquos market interface principles Consideration of the market interface principles is intended to ensure that standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets ReliabilityFirst will coordinate with NERC such that the acknowledgement of receipt of a standard request identified in step 1 notice of comment posting period identified in step 4 and notice for vote identified in step 5 below are concurrently posted on both the ReliabilityFirst and NERC websites


Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete a Regional Reliability Standard Any individual representing an organization (Originator) which is directly or materially impacted by the operation of the BPS within the geographical footprint of the ReliabilityFirst may request via a submittal of a Standard Authorization Request (SAR) form the development modification or deletion of a ReliabilityFirst Standard Any such request shall be submitted to the ReliabilityFirst SPM or hisher designee or by another process as otherwise posted on the ReliabilityFirst website The SAR form may be downloaded from the ReliabilityFirst website The SAR contains a description of the proposed Standard subject matter containing sufficiently descriptive detail to clearly define the purpose scope impacted parties and other relevant information of the proposed Standard The SPM will verify that the submitted SAR form has been adequately completed The SPM may offer the Originator suggestions regarding changes andor improvements to improve clarity and assist the ReliabilityFirst community to understand the Originatorrsquos intent and objectives The Originator is free to accept or reject these suggestions Within 15 days the SPM will electronically acknowledge receipt of the SAR The SPM will forward the adequately complete SAR to the ReliabilityFirst SC at which time the SC will post the SAR for comments within 15 days SARs will be posted and publicly noticed Comments on the SARs will be accepted for a 30-day period from the notice of posting Comments will be accepted online using an internet-based application The SPM will provide a copy of the comments to the Originator and the SC Based on the comments the SC shall make available a consideration of comments report and determine the disposition of the SAR (within 60 calendar days following the SAR commenting period) The disposition decision and decision process shall use the normal ldquobusiness rules and proceduresrdquo of the SC then in effect The SC may take one of the following actions3 in accordance with the ReliabilityFirst Standards Committee Governance document









Any SAR that is accepted by the SC for development of a Standard (or modification or deletion of an existing Standard) shall be posted for public viewing on the ReliabilityFirst website within 30 days of acceptance by the SC The status of posted SARs will be publicly posted Any documentation of the deliberations of the SC concerning SARs shall be made available according to the ldquoReliabilityFirst Standards Committee Governancerdquo document then in effect The SC shall submit a written report to the ReliabilityFirst Board on a periodic basis (at least at every regularly scheduled ReliabilityFirst Board meeting) showing the status of all SARs that have been brought to the SC for consideration Step 2 ndash Formation of the Standard Drafting Team and Declaration of Milestone Date Upon acceptance by the SC of a SAR for development of a new Standard (or modification or deletion of an existing Standard) the SC shall direct the SPM to develop a qualified balance slate for the SDT using the specific directions and preferences of the SC The SPM will send out self-nomination forms to solicit SDT nominees The SDT will consist of a group of people (members of ReliabilityFirst and as appropriate non-members) who collectively have the necessary technical expertise and work process skills The SPM will recommend a slate of ad-hoc individuals or a preexisting task force work group or similar for the SDT based upon the SCrsquos desired SDT capabilities The SC may also direct the SPM to designate an existing ReliabilityFirst committee (or subset thereof) as the SDT augmented by other persons as may be appropriate for the subject matter The SC will insure that SDT membership includes all necessary administrative support This support typically includes a ReliabilityFirst staff member and the Originator if heshe chooses to participate The SC appoints the interim chair (should not be a staff person) of the SDT The SDT will elect the permanent Chair and Vice-chair at its first meeting


The SPM submits the proposed list of names of the SDT to the SC The SC will either accept the recommendations of the SPM or modify the SDT slate as it deems appropriate within 60 days of accepting a SAR for development Upon approval of the SDT slate the SC will declare a preliminary date on which the SDT is expected to have ready a completed draft Standard and associated supporting documentation available for consideration by the ReliabilityFirst membership Step 3 ndash Work and Work Product of the Standard Drafting Team The SDT will then develop a work plan for completing the Standard development work including the establishment of milestones for completing critical elements of the work in sufficient detail to ensure that the SDT will meet the deadline established by the SC or the SDT shall propose an alternative date This plan is then delivered to the SC for its concurrence The SDT is to meet either in person or via electronic means as necessary establish sub-work teams (made up of members of the SDT) as necessary and performs other activities to address the parameters of the SAR and the milestone date(s) established by the SC The work product of the SDT will consist of the following







Upon completion of these tasks the SDT submits these documents to the SC which will verify that the proposed Standard is consistent with the SAR on which it was developed The SDT regularly (at least once each month) informs the SC of its progress in meeting a timely completion of the draft Standard The SDT may request of the SC scope changes of the SAR at any point in the Standard development process The SC may at any time exercise its authority over the Standards development process by directing the SDT to move to Step 4 and post for comment the current work product If there are competing drafts the SC may at its sole discretion post the version(s) of the


draft Standard for comment on the ReliabilityFirst website The SC may take this step at any time after a SDT has been commissioned to develop the Standard Step 4 ndash Comment Posting Period At the direction from the SC the SPM then facilitates the posting of the draft Standard on the ReliabilityFirst website along with a draft implementation plan and supporting documents for a 30-day comment period The SPM shall also inform ReliabilityFirst Members and other potentially interested entities inside or outside of ReliabilityFirst of the posting using typical membership communication procedures then currently in effect or by other means as deemed appropriate As early as the start of the first posting for comment entities may join the Ballot Pool established for the eventual voting on the proposed standard The Ballot Pool category description and associated requirements are in Appendix D Within 30 days of the conclusion of 30-day comment posting period the SDT shall convene and consider changes to the draft Standard the implementation plan andor supporting technical documents based upon comments received Based upon these comments the SDT may elect to return to step 3 to revise the draft Standard implementation plan andor supporting technical documentation The SDT shall prepare a ldquomodification reportrdquo summarizing the comments received and the changes made as a result of these comments The modification report also summarizes comments that were rejected by the SDT and the reason(s) that these comments were rejected in part or whole Responses to all comments will be posted on the ReliabilityFirst website no later than the next posting of the proposed Standard Step 5 ndash Posting for Voting by ReliabilityFirst Registered Ballot Body Upon recommendation of the SDT and if the SC concurs that all of the requirements for development of the Standard have been met the SPM will post the revised draft Standard implementation plan supporting technical documentation and the ldquomodification reportrdquo Once the notice for a vote has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued Entities may register in the BB at any time during the Standards process The BB category description and associated rules are in Appendix D By 1159 PM Central Prevailing Time (CPT) of the seventh day of the 15 day pre-ballot posting period registered BB members intending to vote on the proposed standard must have joined the Ballot Pool established for the eventual voting on the proposed standard being posted The SPM will schedule a Vote by the Ballot Pool which is to be scheduled to commence no sooner than 15 days and no later than 30 days following this posting The Vote by the Ballot Pool is an advisory to the ReliabilityFirst Board


The Ballot Pool shall be allowed to vote over a period of 15 days Votes will be submitted electronically but may be submitted through other means as approved by the SC All BB members are eligible to participate in voting on proposed new Standards Standard revisions or Standard deletions There is a requirement to join a Ballot Pool to participate in voting for each standard The voting results will be composed of only the votes from BB entities that have joined the Ballot Pool for the standard being voted on and responding within the voting period Votes may be accompanied by comments explaining the vote but are not required All comments shall be responded to and posted to the ReliabilityFirst website prior to going to the SC or Board Step 6A ndash Voting Receives Two-Thirds or Greater Majority of Affirmative Category Votes A two-thirds or greater majority4 of votes within a category determines the vote for that category The Initial ballot has passed if there is a two-thirds or greater affirmative majority of category votes (only those categories with votes cast will be considered) during the 15-day voting period and a quorum5 is met If there is at least one (1) Negative vote with comment during the initial ballot then the standard will be posted for a 10-day Recirculation ballot If there are no Negative votes with comments the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7) In the recirculation ballot members of the Ballot Pool shall again be presented the proposed standard (that has not been significantly changed from the previous ballot) along with the reasons for negative votes the responses and any resolution of the differences An insignificant revision is a revision that does not change the scope applicability or intent of any requirement and includes but is not limited to things such as correcting the numbering of a requirement correcting the spelling of a word adding an obviously missing word or rephrasing a requirement for improved clarity Where there is a question as to whether a proposed modification is ldquosubstantiverdquo the Standards Committee shall make the final determination All members of the Ballot Pool shall be permitted to reconsider and change their vote from the prior ballot Members of the Ballot Pool who did not respond to the prior ballot shall be permitted to vote in the recirculation ballot In the recirculation ballot Ballot Pool members may indicate a revision to their original vote otherwise their vote shall remain the same as in their prior ballot Upon successful completion of the initial and recirculation voting periods the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7)



Step 6B ndash Voting Does Not Receive Two-Thirds or Greater Majority of Affirmative Category Votes or a Quorum5 is Not Met If a draft Standard does not receive a two-thirds or greater affirmative majority of votes determined for each category (only those categories with votes cast will be considered) or does not reach quorum during the 15-day Initial voting period the SC may


Direct the existing SDT to reconsider or modify certain aspects of the draft





affirmative category votes cast during the second initial ballot or a quorum is not met the SC will refer the draft Standard and implementation plan to the ReliabilityFirst Board The SC may also submit an assessment opinion and recommendations to the ReliabilityFirst Board (Step 7)

bull Revise the SAR on which the draft Standard was based and remand the

development work back to the original SDT or a newly appointed SDT The resulting draft Standard andor implementation plan will be posted for a second voting period The SC may require a second comment period prior to a second voting period The second posting of the draft Standard implementation plan and supporting documentation shall be within 60 days of the SC action




affirmative category votes cast during the second voting period or a quorum is not met the SC will refer the draft Standard and implementation plan to the ReliabilityFirst Board The SC may also


submit an assessment opinion and recommendations to the ReliabilityFirst Board (Step 7)


under consideration and so notify the ReliabilityFirst Board Step 7 ndash Action by the ReliabilityFirst Board A draft Standard submitted to the ReliabilityFirst Board for action must be publicly posted at least 30 days prior to action by the Board At a regular or special meeting the ReliabilityFirst Board shall consider adoption of the draft Standard The Board will consider the results of the voting and dissenting opinions The Board will consider any advice offered by the SC Draft Standards that received a two-thirds or greater of categories with votes cast shall be delivered to the ReliabilityFirst Board for their action The ReliabilityFirst Board shall be provided with an ldquoinformational packagerdquo which includes








Draft Standards that did not receive a two-thirds or greater of categories with votes cast in the second voting period shall be delivered to the ReliabilityFirst Board for their action The ReliabilityFirst Board shall be provided with an ldquoinformational packagerdquo





Once a regional ReliabilityFirst Standard is approved by the Board the standard will be submitted to NERC for approval and filing with FERC Step 8 - Implementation of a Regional Reliability Standard The SPM will notify the membership upon ReliabilityFirst Board approval of the standard through the normal and customary membership communication procedures and processes then in effect The SPM will also notify the ReliabilityFirst Compliance Staff for integration into the ReliabilityFirst Compliance Program The approval date of each ReliabilityFirst standard is upon Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 ReliabilityFirst standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA Upon approval of a ReliabilityFirst standard action by FERC it is mandatory and enforceable (with monetary penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint The effective date for non-members upon the FERC approval will be determined by the implementation plan that is provided with each new or revised standard



Appendix A Maintenance of Regional Reliability Standards Development Process Significant changes to this Procedure shall begin with the preparation of a SAR and be handled using the same procedure as a request to add modify or delete a Standard The ReliabilityFirst SC has the authority to make lsquominorrsquo changes to this Procedure as deemed appropriate by the SC and subject to the SC voting practices and procedures according to the ldquoReliabilityFirst Standards Committee Governancerdquo document The SC shall promptly notify the ReliabilityFirst Board of such lsquominorrsquo changes to this Procedure for their review and concurrence at the next ReliabilityFirst Board meeting Maintenance of Regional Reliability Standards The SC shall ensure that each Standard shall be reviewed at least once every five years from the effective date of the Standard or the latest revision to the Standard whichever is the later The review process shall be conducted by soliciting comments from the stakeholders If no changes are warranted the SC shall recommend to the ReliabilityFirst Board that the Standard be reaffirmed If the review indicates a need to revise or delete a Standard a SAR shall be prepared and submitted in accordance with the standards development process contained in this Procedure Urgent Action Under certain conditions the SC may designate a proposed Standard or revision to a Standard as requiring urgent action Urgent action may be appropriate when a delay in implementing a proposed Standard or revision could materially impact reliability of the BPS The SC must use its judgment carefully to ensure an urgent action is truly necessary and not simply an expedient way to change or implement a Standard A requester prepares a SAR and a draft of the proposed Standard and submits both to the SPM The SAR must include a justification for urgent action The SPM submits the request to the SC for its consideration If the SC designates the requested Standard or revision as an urgent action item then the SPM shall immediately post the draft for pre-ballot review This posting requires a minimum 30-day posting period before the ballot and applies the same voting procedure as detailed in Step 5 Processing will continue as outlined in the subsequent steps In the event additional drafting is required a SDT will be assembled as outlined in the Procedure Any Standard approved as an urgent action shall have a termination date specified that shall not exceed one year from the approval date Should there be a need to make the Standard permanent then the Standard would be required to go through the full Standard development process All urgent action Standards require ReliabilityFirst Board NERC and FERC approval as outlined for Standards in the regular process


Urgent actions that expire may be renewed using the urgent action process again in the event a permanent Standard is not adopted In determining whether to authorize an urgent action Standard for a renewal ballot the SC shall consider the impact of the Standard on the reliability of the BPS and whether expeditious progress is being made toward a permanent replacement Standard The SC shall not authorize a renewal ballot if there is insufficient progress toward adopting a permanent replacement Standard or if the SC lacks confidence that a reasonable completion date is achievable The intent is to ensure that an urgent action Standard does not in effect take on a degree of permanence due to the lack of an expeditious effort to develop a permanent replacement Standard With these principles there is no predetermined limit on the number of times an urgent action may be renewed However each urgent action Standard renewal shall be effective only upon approval by the ReliabilityFirst Board NERC and FERC Any person or entity including the SDT working on a permanent replacement Standard may at any time submit a SAR proposing that an urgent action Standard become a permanent Standard by following the full Standards process Interpretations of Standards All persons who are directly and materially affected by the reliability of ReliabilityFirst BPS shall be permitted to request an interpretation of the standard The person requesting an interpretation will send a request to the SPM explaining the specific circumstances surrounding the request and what clarifications are required as applied to those circumstances The request should indicate the material impact to the requesting party or others caused by the lack of clarity or a possibly incorrect interpretation of the standard The SPM along with guidance from the SC will assemble a team with the relevant expertise to address the request The Interpretation Drafting Team (IDT) typically consists of members from the original SDT The SPM submits the proposed list of names of the IDT to the SC The SC will either accept the recommendations of the SPM or modify the IDT slate As soon as practical (not more than 45 days) the team will prepare an initial draft interpretation of the standard addressing the issues raised Once the IDT has completed the initial draft interpretation the team will post the draft for a 30-day informal6 stakeholder comment period The IDT will review the stakeholder feedback and may make changes before preparing a final draft of the interpretation The IDT will then forward the draft interpretation to the SPM The SPM will forward the interpretation to the Reliability Committee (RC) Barring receipt of an opinion from the RC within 21 calendar days that the interpretation is not technically appropriate for the Standard

6 An informal comment period does not require the IDT to respond to every stakeholder comment and is only used to make potential changes for the final draft of the interpretation


respectively the SPM will forward the interpretation to the SC The SC will determine if the interpretation is consistent with the Standard and does not add additional requirements to the standard The SC will forward the interpretation to the ReliabilityFirst Board for informational purposes as being appended to the approved Standard Note In the event that the RC determines that the interpretation makes the standard technically inappropriate the RC shall provide an explanation of its reasoning to the SPM and IDT for inclusion in a subsequent revision In either case the IDT and SPM will continue to re-circulate the interpretation as stated above The interpretation will stand until such time as the standard is revised through the normal process at which time the standard will be modified to incorporate the clarifications provided by the interpretation Appeals Persons who have directly and materially affected interests and who have been or will be adversely affected by any substantive or procedural action or inaction related to the development approval revision reaffirmation or withdrawal of a Standard shall have the right to appeal This appeals process applies only to the Standards process as defined in this Procedure The burden of proof to show adverse effect shall be on the appellant Appeals shall be made within 30 days of the date of the action purported to cause the adverse effect except appeals for inaction which may be made at any time In all cases the request for appeal must be made prior to the next step in the process The final decisions of any appeal shall be documented in writing and made public The appeals process has two levels with the goal of expeditiously resolving the issue to the satisfaction of the participants Level 1 Appeal Level 1 is the required first step in the appeals process The appellant submits a complaint in writing to the SPM that describes the substantive or procedural action or inaction associated with a Standard or the standards process The appellant describes in the complaint the actual or potential adverse impact to the appellant Assisted by any necessary staff and committee resources the SPM shall prepare a written response addressed to the appellant as soon as practical but not more than 45-days after receipt of the complaint If the appellant accepts the response as a satisfactory resolution of the issue both the complaint and response will be made a part of the public record associated with the standard Level 2 Appeal


If after the Level 1 Appeal the appellant remains unsatisfied with the resolution as indicated by the appellant in writing to the SPM the SPM shall convene a Level 2 Appeals Panel This panel shall consist of five members total appointed by the ReliabilityFirst Board In all cases Level 2 Appeals Panel members shall have no direct affiliation with the participants in the appeal The SPM shall post the complaint and other relevant materials and provide at least 30-days notice of the meeting of the Level 2 Appeals Panel In addition to the appellant any person that is directly and materially affected by the substantive or procedural action or inaction referenced in the complaint shall be heard by the panel The panel shall not consider any expansion of the scope of the appeal that was not presented in the Level 1 Appeal The panel may in its decision find for the appellant and remand the issue to the SC with a statement of the issues and facts in regard to which fair and equitable action was not taken The panel may find against the appellant with a specific statement of the facts that demonstrate fair and equitable treatment of the appellant and the appellantrsquos objections The panel may not however revise approve disapprove or adopt a reliability standard The actions of the Level 2 Appeals Panel shall be publicly posted In addition to the foregoing a procedural objection that has not been resolved may be submitted to the ReliabilityFirst Board for consideration at the time the Board decides whether to adopt a particular reliability standard The objection must be in writing signed by an officer of the objecting entity and contain a concise statement of the relief requested and a clear demonstration of the facts that justify that relief The objection must be filed no later than 30-days after the announcement of the vote on the Standard in question





ID




Request Date



Company

New Standard









































yes or no


yes or no


yes or no


yes or no







Related SARs






on (date)





Step 1

SC Action

Remand SAR

Accept SAR

Reject SAR

Post Request for

SDT

Step 2

Appoint SDT









to SPM




SC Action

Revise SAR



SC Assessment



2nd Category Vote


Affirmative


Affirmative

Yes No

Yes

No


Step 5 Step 6B

Step 6A

Step 7


No


Yes


Affirmative Yes

A


companies

No

B

Yes

Board Approval

No

A

B

A

Step 8


Appendix D Ballot Pool Categories For the purposes of category Ballot Pool registration and voting a person or entity may join the registered Ballot Pool to vote on standards whether or not such person or entity is a member of ReliabilityFirst A corporation or other organization with integrated operations or with affiliates that qualifies to belong to more than one category (eg Transmission Owners and Load Serving Entities) may join and vote once in each category for which it qualifies provided that each category constitutes a separate membership in the Ballot Body and the organization is represented in each category by a different representative Affiliated entities are collectively limited to one membership in each category in the Ballot Pool for which they are qualified Category 1 ndash Transmission Owner Transmission Operator Transmission Service



Category 5 ndash Distribution Provider Ballot Body Registration Entities may register in the BB at any time during the Standards process The SPM shall review all applications for joining the BB and make a determination of whether they qualify for the self-selection category In order to comment or vote you must have an active membership in the BB When you submit your registration request to join the BB you are placed in a ldquopending stagerdquo until your account is activated Activation of your account may take up to 24 hours You will be unable to submit comments or join a Ballot Pool until your account is activated The contact designated as primary representative to ReliabilityFirst is the voting member with the secondary contact as the backup Note Registration for a BB is not the same as registration for the compliance registry Although the terminology used to describe the BB categories in most cases has the same meaning as the terms used in the NERC Functional Model registration in a BB goes beyond the compliance registry in that entities smaller than those stated in the compliance



registry guidelines are allowed to register in a BB Entities shall have evidence that they qualify for the BB category they register in Such evidence shall be available for the SPM review to verify BB registration and may include compliance registration Ballot Pool Formation In order to participate in voting on a particular standard an entity must join the Ballot Pool being established for the standard as follows 1 ndash As early as the start of the first posting for comment entities may join the Ballot Pool established for the eventual voting on the proposed standard being posted 2 - By close of business of the seventh day of the 15 day pre ballot posting period entities wishing to vote must have joined the Ballot Pool established for the eventual voting on the proposed standard being posted

Attachment B ReliabilityFirst Standards Development Procedure


(Redline)



Procedure






Version 3


Table of Contents

Introduction 1 Background 2 Regional Reliability Standard Definition Characteristics and Elements 3 Roles in the Regional Reliability Standards Development Process 7 Regional Reliability Standards Development Process 8 Appendix A Maintenance of Regional Reliability Standards Development Processhelliphelliphellip17





Appendix B Standard Authorization Request 21 Appendix C Flowchart for Standards Process 28 Appendix D Ballot Pool Categories and Registration 30


Page 1 of 31




Introduction This procedure establishes the process for adoption of a Regional Reliability Standard1 (hereinafter referred to as ldquoStandardrdquo) of the ReliabilityFirst Corporation (ReliabilityFirst) and the development of consensus for adoption approval revision reaffirmation and deletion of such Standards1 ReliabilityFirst Standards provide for the reliable regional and sub-regional planning and operation of the Bulk Power System2 (BPS) consistent with Good Utility Practice2 within the ReliabilityFirst geographical footprint This procedure was developed under the direction of the ReliabilityFirst Board of Directors (Board) who may request changes to this ReliabilityFirst Reliability Standards Development Procedure (hereinafter referred to as ldquothis Procedurerdquo) as deemed appropriate A procedure for revising this Procedure is contained in Appendix A This Procedure is consistent with the North American Electric Reliability CouncilCorporation (NERC) Reliability Standards Development Procedure Proposed StandardsReliabilityFirst standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA No Standard shall be effective within the ReliabilityFirst area unless filed by NERC with FERC and approved by FERC The approval date of each ReliabilityFirst standard is upon ReliabilityFirst Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 The ReliabilityFirst standard is mandatory and enforceable (with monetary penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint upon approval by FERC The effective date for non-members upon the FERC approval will be determined by the implementation plan that is provided with each new or revised standard

1 Legacy standards such as ECAR Documents MAIN Guides and MAAC Procedures shall be considered ReliabilityFirst Regional Reliability Standards for the purposes of this document until otherwise acted upon by the ReliabilityFirst Board 2 As defined in the ReliabilityFirst By-laws 3 By applying for and becoming a Regular or Associate Member of the Corporation each Member agrees to comply with all Reliability Standards all NERC standards and requirements and the other obligations of Members of the Corporation set forth in the ReliabilityFirst Bylaws or duly adopted by the Board in order to achieve the purposes of the Corporation



Page 2 of 31



ReliabilityFirst Standards shall provide for as much uniformity as possible with NERC reliability standards across the interconnected BPS A ReliabilityFirst Standard shall be more stringent than a NERC reliability standard including a regional difference that addresses matters that the NERC reliability standard does not or shall be a regional difference necessitated by a physical difference in the BPS A ReliabilityFirst Standard that satisfies the statutory and regulatory criteria for approval of proposed NERC reliability standards and that is more stringent than a NERC reliability standard would generally be acceptable ReliabilityFirst Standards when approved by FERC shall be made part of the body of NERC reliability standards and shall be enforced upon all applicable BPS owners operators and users within the ReliabilityFirst area regardless of membership in the region Background Regions may develop through their own processes separate ldquoRegional Standardsrdquo (ReliabilityFirst Standards) that go beyond add detail to or implementaid implementation of NERC reliability standards or otherwise address issues that are not addressed in NERC reliability standards As a condition of ReliabilityFirst membership all ReliabilityFirst Members2 agree to adhere to the NERC reliability standards As such the ReliabilityFirst and its Members will adhere to the NERC reliability standards in addition to the ReliabilityFirst Standards NERC reliability standards and the ReliabilityFirst Standards are both to be included within the ReliabilityFirst Compliance Program









Page 3 of 31




As contained in the ReliabilityFirst By-laws ReliabilityFirst ldquoRegional Reliability Standardrdquo shall mean a type of Reliability Standard that is applicable only within a particular Regional Entity or group of Regional Entities A Regional Reliability Standard may augment add detail to or implement another Reliability Standard or cover matters not addressed by other Reliability Standards Regional Reliability Standards upon adoption by NERC and approval by the Commission shall be Reliability Standards and shall be enforced within the applicable Regional Entity or Regional Entities pursuant to delegated authorities Inherent in this definition a ReliabilityFirst Standard will define certain obligations or requirements of entities that own operate plan and use the BPS within the ReliabilityFirst geographical footprint These obligations or requirements as contained in the ReliabilityFirst Standards are to be measurable and consistent with Good Utility Practice Standards are not to include processes or procedures that implement a Standard In addition obligations requirements or procedures imposed upon ReliabilityFirst by NERC reliability standards are not to be ReliabilityFirst Standards unless those obligations requirements or procedures require the establishment of a ldquopolicy or standardrdquo as defined by the ReliabilityFirst By-laws Characteristics of a Regional Reliability Standard A Standard is policy or standard including adequacy criteria to provide for the reliable regional and sub-regional planning and operation of the BPS consistent with Good Utility Practice A Standard shall generally have the following characteristics




Format Requirements of a Regional Reliability Standard A Standard shall consist of the format requirements shown in the Regional Reliability Standard Template These requirements apply to the development and revision of Standards These requirements are necessary to achieve Standards that are measurable




Page 4 of 31



enforceable and consistent Supporting documents to aid in the implementation of a Standard may be referenced by the Standard but are not part of the Standard itself The most current version of the approved NERC Reliability Standard template and its associated elements posted on the NERC website will be used at the time of the development of a ReliabilityFirst Regional Reliability Standard if different from the elements listed below








Requirement(s) Explicitly stated technical performance and preparedness requirements Each requirement identifies what entity is responsible and what action is to be performed or what outcome is to be achieved EachCompliance is mandatory for each statement in the requirements section shall be a statement for which compliance is mandatory

Formatted Table


Page 5 of 31



Risk Factor(s)


Measure(s) Each requirement shall be addressed by one or more measurements Measurements that will be used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measurement identifies to whom the measurement applies Each measurement shall be tangible practical and as objective as is practical Achieving the full compliance level of each measurement should beis a necessary and sufficient indicator that the requirement was met



Page 6 of 31






for measuring performance or outcomes bull The process that will be used to evaluate data or information for

the purpose of assessing performance or outcomes bull The entity that is responsible for evaluating data or information to

assess performance or outcomes bull The time period in which performance or outcomes is measured

evaluated and then reset bull Measurement dataData retention requirements and assignment of

responsibility for data archiving bull Violation severity levels

Formatted Indent Left 018 Hanging 013 Outline numbered + Level 1 +Numbering Style Bullet + Aligned at 025 +Tab after 05 + Indent at 05


Page 7 of 31






Each ReliabilityFirst Standard shall have an associated implementation plan describing the effective date of the Standard or effective dates if there is a phased implementation The implementation plan may also describe the implementation of the Standard in the compliance program and other considerations in the initial use of the Standard such as necessary tools training etc The implementation plan must be posted for at least one public comment period and isbe approved as part of the ballot of the standard


This section references related documents that support reasons for or otherwise provide additional information related to the Standard Examples include but are not limited to bull Glossary of Terms bull Developmental history of the Standard and prior versions bull Subcommittee(s) responsible for Standard bull Notes pertaining to implementation or compliance bull Standard references bull ProceduresPractices bull Training andor Technical Reference


Formatted Table

Formatted Indent Left 015 Hanging 013 Outline numbered + Level 1 +Numbering Style Bullet + Aligned at 025 +Tab after 05 + Indent at 05 Tab stops 028 List tab


Page 8 of 31



will advise the ReliabilityFirst Board on Standards presented for adoption by the ReliabilityFirst Board Standards Process Manager (SPM) ndash A person or persons on the ReliabilityFirst staff assigned the task of ensuring that the development revision or deletion of Standards is in accordance with this Procedure The SPM works to ensure the integrity of the process and consistency of quality and completeness of the Standards The SPM facilitates the administration of all actions contained in all steps in the process Standards Process Staff ndash Employees of the ReliabilityFirst that work with or for the SPM Interim Compliance Committee (ICC) ndash The ReliabilityFirst committee responsible for the administration of the ReliabilityFirst Compliance Program The duties of this committee includes but not limited to providing inputs and comments during the standards development process to ensure the measures will be effective and other aspects of the Compliance Program can be practically implemented Standard Drafting Team (SDT) ndash Normally aA team of technical experts and typically includesincluding a member of the ReliabilityFirst Standards staff and the Originator assigned the task of developing a proposed Standard based upon an approved SAR using the Standard development process contained in this Procedure Ballot Body (BB) ndash The Ballot Body comprises all entities that qualify for one or more of the categories and are registered with ReliabilityFirst as potential ballot participants in the voting on standards The categories of registration within the Ballot Body and the registration process are described in Appendix D Ballot Pool ndash The Ballot Pool is comprised of those members of the Ballot Body that register to vote for each particular standard that is up for vote A separate Ballot Pool is established for each standard up for vote Only individuals who have joined the Ballot Pool for that particular standard are eligible to vote on a standard Reliability Committee (RC) ndash The ReliabilityFirst RC serves as a technical advisory body to address the reliability related activities required by the Reliability Standards via review and discussion of the regional activities as requested by the SC Regional Reliability Standard Development Process (Flow chart of Process shown in Appendix C) Assumptions and Prerequisites The ReliabilityFirst Regional Reliability Standards Development Process has the following characteristics


Page 9 of 31




bull Openness - Participation is open to all Organizations who are directly

and materially affected by the ReliabilityFirst region BPS reliability There shall be no undue financial barriers to participation Participation shall not be conditioned upon membership in the ReliabilityFirst and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements Meetings of SDTs are open to the ReliabilityFirst membership and to others









Each standard shall enable or support one or more of the reliability principles thereby ensuring that each standard serves a purpose in support of the reliability of the regional BPS Each standard shall also be consistent with all of the reliability principles thereby ensuring that no standard undermines reliability through an unintended consequence While ReliabilityFirst Standards are intended to promote reliability they must at the same time accommodate competitive electricity markets Reliability is a necessity for electricity markets and robust electricity markets can support reliability Recognizing that BPS reliability and electricity markets are inseparable and mutually interdependent all ReliabilityFirst Standards shall be consistent with NERCrsquos market interface principles Consideration of the market interface principles is intended to ensure that




Page 10 of 31



standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets ReliabilityFirst will coordinate with NERC such that the acknowledgement of receipt of a standard request identified in step 1 notice of comment posting period identified in step 4 and notice for vote identified in step 5 below are concurrently posted on both the ReliabilityFirst and NERC websites Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete a Regional Reliability Standard Any individual representing an organization (Originator) which is directly or materially impacted by the operation of the BPS within the geographical footprint of the ReliabilityFirst may request via a submittal of a Standard Authorization Request (SAR) form the development modification or deletion of a ReliabilityFirst Standard Any such request shall be submitted to the ReliabilityFirst SPM or hisher designee or by another process as otherwise posted on the ReliabilityFirst website The SAR form may be downloaded from the ReliabilityFirst website The SAR contains a description of the proposed Standard subject matter containing sufficiently descriptive detail to clearly define the purpose scope impacted parties and other relevant information of the proposed Standard The SPM will verify that the submitted SAR form has been adequately completed The SPM may offer the Originator suggestions regarding changes andor improvements to improve clarity and assist the ReliabilityFirst community to understand the Originatorrsquos intent and objectives The Originator is free to accept or reject these suggestions Within 15 days the SPM will electronically acknowledge receipt of the SAR The SPM will forward allthe adequately completed SARs complete SAR to the ReliabilityFirst SC Within 60 at which time the SC will post the SAR for comments within 15 days SARs will be posted and publicly noticed Comments on the SARs will be accepted for a 30-day period from the notice of receiptposting Comments will be accepted online using an internet-based application The SPM will provide a copy of an adequately completed SARthe comments to the Originator and the SC Based on the comments the SC shall make available a consideration of comments report and determine the disposition of the SAR (within 60 calendar days following the SAR commenting period) The disposition decision and decision process shall use the normal ldquobusiness rules and proceduresrdquo of the SC then in effect The SC may take one of the following actions3 in accordance with the ReliabilityFirst Standards Committee Governance document



Page 11 of 31









Any SAR that is accepted by the SC for development of a Standard (or modification or deletion of an existing Standard) shall be posted for public viewing on the ReliabilityFirst website within no greater than 30 days of acceptance by the SC The status of posted SARs will be publicly noted at regularly scheduled (appropriately two weeks) intervalsposted Any documentation of the deliberations of the SC concerning SARs shall be made available according to the ldquoReliabilityFirst Standards Committee Governancerdquo document then in effect The SC shall submit a written report to the ReliabilityFirst Board on a periodic basis (at least at every regularly scheduled ReliabilityFirst Board meeting) showing the status of all SARs that have been brought to the SC for consideration Step 2 ndash Formation of the Standard Drafting Team and Declaration of Milestone Date Upon acceptance by the SC of a SAR for development of a new Standard (or modification or deletion of an existing Standard) the SC shall direct the SPM to develop a qualified balance slate for the SDT using the specific directions and preferences of the SC The SPM will send out self-nomination forms to solicit SDT nominees The SDT will consist of a group of people (members of ReliabilityFirst and as appropriate non-members) who collectively have the necessary technical expertise and work process skills The SPM will recommend a slate of ad-hoc individuals or a preexisting task force work group or similar for the SDT based upon the SCrsquos desired SDT capabilities



Formatted List Paragraph Adjust spacebetween Latin and Asian text Adjust spacebetween Asian text and numbers



Page 12 of 31



The SC may also direct the SPM to designate an existing ReliabilityFirst committee (or subset thereof) as the SDT augmented by other persons as may be appropriate for the subject matter The SC will insure that SDT membership includes all necessary administrative support This support typically includes a ReliabilityFirst staff member and the Originator if heshe chooses to participate The SC appoints the interim chair (should not be a staff person) of the SDT The SDT will elect the permanent Chair and Vice-chair at its first meeting The SPM submits the proposed list of names of the SDT to the SC The SC will either accept the recommendations of the SPM or modify the SDT slate as it deems appropriate within 60 days of accepting a SAR for development Upon approval of the SDT slate the SC will declare a preliminary date on which the SDT is expected to have ready a completed draft Standard and associated supporting documentation available for consideration by the ReliabilityFirst membership Step 3 ndash Work and Work Product of the Standard Drafting Team The SDT will then develop a work plan for completing the Standard development work including the establishment of milestones for completing critical elements of the work in sufficient detail to ensure that the SDT will meet the date objectivedeadline established by the SC or the SDT shall propose an alternative date This plan is then delivered to the SC for its concurrence The SDT is to meet either in person or via electronic means as necessary establish sub-work teams (made up of members of the SDT) as necessary and performs other activities to address the parameters of the SAR and the milestone date(s) established by the SC The work product of the SDT will consist of the following







Upon completion of these tasks the SDT submits these documents to the SC which will verify that the proposed Standard is consistent with the SAR on which it was developed



Page 13 of 31



The SDT regularly (at least once each month) informs the SC of its progress in meeting a timely completion of the draft Standard The SDT may request of the SC scope changes of the SAR at any point in the Standard development process The SC may at any time exercise its authority over the Standards development process by directing the SDT to move to Step 4 and post for comment the current work product If there are competing drafts the SC may at its sole discretion have postedpost the version(s) of the draft Standard for comment on the ReliabilityFirst website The SC may take this step at any time after a SDT has been commissioned to develop the Standard Step 4 ndash Comment Posting Period At the direction from the SC the SPM then facilitates the posting of the draft Standard on the ReliabilityFirst website along with a draft implementation plan and supporting documents for a 30-day comment period The SPM shall also inform ReliabilityFirst Members and other potentially interested entities inside or outside of ReliabilityFirst of the posting using typical membership communication procedures then currently in effect or by other means as deemed appropriate As early as the start of the first posting for comment entities may join one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted The Ballot Pool category description and associated requirements are in Appendix D Within 30 days of the conclusion of 30-day comment posting period the SDT shall convene and consider changes to the draft Standard the implementation plan andor supporting technical documents based upon comments received Based upon these comments the SDT may elect to return to step 3 to revise the draft Standard implementation plan andor supporting technical documentation The SDT shall prepare a ldquomodification reportrdquo summarizing the comments received and the changes made as a result of these comments The modification report also summarizes comments that were rejected by the SDT and the reason(s) that these comments were rejected in part or whole Responses to all comments will be posted on the ReliabilityFirst website no later than the next posting of the proposed Standard Step 5 ndash Posting for Voting by ReliabilityFirst Registered Ballot Body Upon recommendation of the SDT and if the SC concurs that all of the requirements for development of the Standard have been met the SPM will post the revised draft Standard implementation plan supporting technical documentation and the ldquomodification reportrdquo Once the notice for a vote has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued


Page 14 of 31



Entities may register in the BB at any time during the Standards process The BB category description and associated rules are in Appendix D By 1159 PM Central Prevailing Time (CPT) of the seventh day of the 15 day pre -ballot posting period registered BB entitiesmembers intending to vote on the proposed standard must have joined one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted The SPM will schedule a Vote by the Ballot Pool which is to be scheduled to commence no sooner than 15 days and no later than 30 days following this posting The Vote by the Ballot Pool is an advisory to the ReliabilityFirst Board The Ballot Pool shall be allowed to vote over a period of 15 days It is expected that votesVotes will be submitted electronically but may be submitted through other means as approved by the SC All entities registered as part of the BB members are eligible to participate in voting on proposed new Standards Standard revisions or Standard deletions There is a requirement to separately join a Ballot Pool to participate in voting for each standard Each entity can join only in one category of the Ballot Pool and shall have one vote The voting results will be composed of only the votes from BB entities that have joined the Ballot Pool for the standard being voted on and responding within the 15 day voting period Votes may be accompanied by comments explaining the vote but are not required All comments shall be responded to and posted to the ReliabilityFirst website prior to going to the SC or Board Step 6A ndash Voting Receives SimpleTwo-Thirds or Greater Majority of Affirmative Category Votes A simpletwo-thirds or greater majority45 of votes within a category determines the vote for that category If The Initial ballot has passed if there is a simpletwo-thirds or greater affirmative majority of category votes (only those categories with votes cast will be considered) during the 15-day voting period and a quorum is met (a quorum consists of a simple majority of individuals who have joined the Ballot Pool) the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7)6 is met If there is at least one (1) Negative vote with comment during the initial ballot then the standard will be posted for a 10-day Recirculation ballot If there are no Negative votes with comments the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7) In the recirculation ballot members of the Ballot Pool shall again be presented the proposed standard (that has not been significantly changed from the previous ballot) along with the reasons for negative votes the responses and any resolution of the differences An insignificant revision is a revision that does not change the scope 4 For the purposes of determining majority within a category an abstention is not considered a vote 5 For the purposes of determining majority within a category an abstention is not considered a vote 6 A quorum is achieved when three-fourths (75) or greater of the ballot pool casts a vote

Formatted Font Not Italic




Page 15 of 31



applicability or intent of any requirement and includes but is not limited to things such as correcting the numbering of a requirement correcting the spelling of a word adding an obviously missing word or rephrasing a requirement for improved clarity Where there is a question as to whether a proposed modification is ldquosubstantiverdquo the Standards Committee shall make the final determination All members of the Ballot Pool shall be permitted to reconsider and change their vote from the prior ballot Members of the Ballot Pool who did not respond to the prior ballot shall be permitted to vote in the recirculation ballot In the recirculation ballot Ballot Pool members may indicate a revision to their original vote otherwise their vote shall remain the same as in their prior ballot Upon successful completion of the initial and recirculation voting periods the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7) Step 6B ndash Voting Does Not Receive SimpleTwo-Thirds or Greater Majority of Affirmative Category Votes or a QuorumQuorum5 is Not Met If a draft Standard does not receive a simpletwo-thirds or greater affirmative majority of votes determined for each category (only those categories with votes cast will be considered) or does not reach quorum during the 15-day voting period or a quorum is not met during the 15-dayInitial voting period the SC may


bull Direct the existing SDT to reconsider or modify certain aspects of the draft



with votes cast and a quorum is met during the second voting periodinitial ballot and second recirculation ballot the SC will forward it to the ReliabilityFirst Board for action (Step 7)


of affirmative category votes cast during the second voting periodinitial ballot or a quorum is not met the SC will refer the draft Standard and implementation plan to the ReliabilityFirst Board The SC may also submit an assessment opinion and recommendations to the ReliabilityFirst Board (Step 7)


Formatted Indent Left 025

Formatted Bulleted + Level 1 + Aligned at 025 + Tab after 025 + Indent at 05


Page 16 of 31



bull Revise the SAR on which the draft Standard was based and remand the development work back to the original SDT or a newly appointed SDT The resulting draft Standard andor implementation plan will be posted for a second voting period The SC may require a second comment period prior to a second voting period The second posting of the draft Standard implementation plan and supporting documentation shall be within 60 days of the SC action


with votes cast during the second voting period and a quorum is met during the second initial ballot and second recirculation ballot the SC will forward it to the ReliabilityFirst Board for action (Step 7)


of affirmative category votes cast during the second voting period or a quorum is not met the SC will refer the draft Standard and implementation plan to the ReliabilityFirst Board The SC may also submit an assessment opinion and recommendations to the ReliabilityFirst Board (Step 7)


under consideration and so notify the ReliabilityFirst Board Step 7 ndash Action by the ReliabilityFirst Board A draft Standard submitted to the ReliabilityFirst Board for action must be publicly posted at least 30 days prior to action by the Board At a regular or special meeting the ReliabilityFirst Board shall consider adoption of the draft Standard The Board will consider the results of the voting and dissenting opinions The Board will consider any advice offered by the SC Draft Standards that received a simple affirmative majoritytwo-thirds or greater of categories with votes cast shall be delivered to the ReliabilityFirst Board for their action The ReliabilityFirst Board shall be provided with an ldquoinformational packagerdquo which includes








Page 17 of 31





Draft Standards that did not receive a simple affirmative majoritytwo-thirds or greater of categories with votes cast in the second voting period shall be delivered to the ReliabilityFirst Board for their action The ReliabilityFirst Board shall be provided with an ldquoinformational packagerdquo




Once a regional ReliabilityFirst Standard is approved by the Board the standard will be submitted to NERC for approval and filing with FERC Step 8 - Implementation of a Regional Reliability Standard Upon approval of a draft Standard action by FERC theThe SPM will notify the membership upon ReliabilityFirst Board approval of the effective datestandard through the normal and customary membership communication procedures and processes then in effect The SPM will also notify the ReliabilityFirst Compliance Staff for integration into the ReliabilityFirst Compliance Program The approval date of each ReliabilityFirst standard is upon Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 ReliabilityFirst standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA Upon approval of a ReliabilityFirst standard action by FERC it is mandatory and enforceable (with monetary







Page 18 of 31



penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint The effective date for non-members upon the FERC approval will be determined by the implementation plan that is provided with each new or revised standard


Page 19 of 31



Appendix A Maintenance of Regional Reliability Standards Development Process Significant changes to this Procedure shall begin with the preparation of a SAR and be handled using the same procedure as a request to add modify or delete a Standard The ReliabilityFirst SC has the authority to make lsquominorrsquo changes to this Procedure as deemed appropriate by the SC and subject to the SC voting practices and procedures according to the ldquoReliabilityFirst Standards Committee Governancerdquo document then in effect The SC shall promptly notify the ReliabilityFirst Board of such lsquominorrsquo changes to this Procedure for their review and concurrence at the next ReliabilityFirst Board meeting Maintenance of Regional Reliability Standards The SC shall ensure that each Standard shall be reviewed at least once every five years from the effective date of the Standard or the latest revision to the Standard whichever is the later The review process shall be conducted by soliciting comments from the stakeholders If no changes are warranted the SC shall recommend to the ReliabilityFirst Board that the Standard be reaffirmed If the review indicates a need to revise or delete a Standard a SAR shall be prepared and submitted in accordance with the standards development process contained in this Procedure Urgent Action Under certain conditions the SC may designate a proposed Standard or revision to a Standard as requiring urgent action Urgent action may be appropriate when a delay in implementing a proposed Standard or revision could materially impact reliability of the BPS The SC must use its judgment carefully to ensure an urgent action is truly necessary and not simply an expedient way to change or implement a Standard A requester prepares a SAR and a draft of the proposed Standard and submits both to the SPM The SAR must include a justification for urgent action The SPM submits the request to the SC for its consideration If the SC designates the requested Standard or revision as an urgent action item then the SPM shall immediately post the draft for pre-ballot review This posting requires a minimum 30-day posting period before the ballot and applies the same voting procedure as detailed in Step 5 Processing will continue as outlined in the subsequent steps In the event additional drafting is required a SDT will be assembled as outlined in the Procedure Any Standard approved as an urgent action shall have a termination date specified that shall not exceed one year from the approval date Should there be a need to make the Standard permanent then the Standard would be required to go through the full Standard


Page 20 of 31



development process All urgent action Standards require ReliabilityFirst Board NERC and FERC approval as outlined for Standards in the regular process Urgent actions that expire may be renewed using the urgent action process again in the event a permanent Standard is not adopted In determining whether to authorize an urgent action Standard for a renewal ballot the SC shall consider the impact of the Standard on the reliability of the BPS and whether expeditious progress is being made toward a permanent replacement Standard The SC shall not authorize a renewal ballot if there is insufficient progress toward adopting a permanent replacement Standard or if the SC lacks confidence that a reasonable completion date is achievable The intent is to ensure that an urgent action Standard does not in effect take on a degree of permanence due to the lack of an expeditious effort to develop a permanent replacement Standard With these principles there is no predetermined limit on the number of times an urgent action may be renewed However each urgent action Standard renewal shall be effective only upon approval by the ReliabilityFirst Board NERC and FERC Any person or entity including the SDT working on a permanent replacement Standard may at any time submit a SAR proposing that an urgent action Standard become a permanent Standard by following the full Standards process Interpretations of Standards All persons who are directly and materially affected by the reliability of ReliabilityFirst BPS shall be permitted to request an interpretation of the standard The person requesting an interpretation will send a request to the SPM explaining the specific circumstances surrounding the request and what clarifications are required as applied to those circumstances The request should indicate the material impact to the requesting party or others caused by the lack of clarity or a possibly incorrect interpretation of the standard The SPM along with guidance from the SC will assemble a team with the relevant expertise to address the request The Interpretation Drafting Team (IDT) typically consists of members from the original SDT The SPM submits the proposed list of names of the IDT to the SC The SC will either accept the recommendations of the SPM or modify the IDT slate As soon as practical (not more than 45 days) the team will prepare an initial draft a written interpretation toof the standard addressing the issues raised Once the IDT has completed athe initial draft interpretation to the Standard addressing only the issues raised the team will post the draft for a 30-day informal7 stakeholder comment period The IDT will review the stakeholder feedback and may make changes before preparing a final draft of the interpretation The IDT will then forward the draft interpretation to the 7 An informal comment period does not require the IDT to respond to every stakeholder comment and is only used to make potential changes for the final draft of the interpretation


Page 21 of 31



SPM The SPM will forward the draft interpretation to the Interim Compliance Committee (ICC)The ICC is to assess if the inclusion of the interpretation lessens the measurability of the Standard In addition the The SPM will forward the interpretation to the Reliability Committee (RC) Barring receipt of an opinion from either the ICC or RC within 21 calendar days that the interpretation sufficiently lessens measurability or is not technically appropriate for the Standard respectively the SPM will forward the interpretation to the SC The SC will determine if the interpretation is consistent with the Standard and does not add additional requirements to the standard The SC will forward the interpretation to the ReliabilityFirst Board for informational purposes as being appended to the approved Standard Note In the event that the ICCRC determines that measurability is lessened the ICCinterpretation makes the standard technically inappropriate the RC shall provide an explanation of its reasoning to the SPM and IDT for inclusion in a subsequent revision The RC shall in a similar manner provide an explanation of its reasoning if it determines that the interpretation makes the standard technically inappropriate In either case the IDT and SPM will continue to re-circulate the interpretation as stated above The interpretation will stand until such time as the standard is revised through the normal process at which time the standard will be modified to incorporate the clarifications provided by the interpretation Appeals Persons who have directly and materially affected interests and who have been or will be adversely affected by any substantive or procedural action or inaction related to the development approval revision reaffirmation or withdrawal of a Standard shall have the right to appeal This appeals process applies only to the Standards process as defined in this Procedure The burden of proof to show adverse effect shall be on the appellant Appeals shall be made within 30 days of the date of the action purported to cause the adverse effect except appeals for inaction which may be made at any time In all cases the request for appeal must be made prior to the next step in the process The final decisions of any appeal shall be documented in writing and made public The appeals process provideshas two levels with the goal of expeditiously resolving the issue to the satisfaction of the participants Level 1 Appeal Level 1 is the required first step in the appeals process The appellant submits a complaint in writing to the SPM that describes the substantive or procedural action or inaction associated with a Standard or the standards process The appellant describes in the complaint the actual or potential adverse impact to the appellant Assisted by any


Page 22 of 31



necessary staff and committee resources the SPM shall prepare a written response addressed to the appellant as soon as practical but not more than 45-days after receipt of the complaint If the appellant accepts the response as a satisfactory resolution of the issue both the complaint and response will be made a part of the public record associated with the standard Level 2 Appeal If after the Level 1 Appeal the appellant remains unsatisfied with the resolution as indicated by the appellant in writing to the SPM the SPM shall convene a Level 2 Appeals Panel This panel shall consist of five members total appointed by the ReliabilityFirst Board In all cases Level 2 Appeals Panel members shall have no direct affiliation with the participants in the appeal The SPM shall post the complaint and other relevant materials and provide at least 30-days notice of the meeting of the Level 2 Appeals Panel In addition to the appellant any person that is directly and materially affected by the substantive or procedural action or inaction referenced in the complaint shall be heard by the panel The panel shall not consider any expansion of the scope of the appeal that was not presented in the Level 1 Appeal The panel may in its decision find for the appellant and remand the issue to the SC with a statement of the issues and facts in regard to which fair and equitable action was not taken The panel may find against the appellant with a specific statement of the facts that demonstrate fair and equitable treatment of the appellant and the appellantrsquos objections The panel may not however revise approve disapprove or adopt a reliability standard The actions of the Level 2 Appeals Panel shall be publicly posted In addition to the foregoing a procedural objection that has not been resolved may be submitted to the ReliabilityFirst Board for consideration at the time the Board decides whether to adopt a particular reliability standard The objection must be in writing signed by an officer of the objecting entity and contain a concise statement of the relief requested and a clear demonstration of the facts that justify that relief The objection must be filed no later than 30-days after the announcement of the vote on the Standard in question


Page 23 of 31








Company

New Standard







Request Date

ID




Page 24 of 31



















Page 25 of 31



















Page 26 of 31





yes or no


yes or no


yes or no


yes or no



Page 27 of 31





Page 28 of 31





Related SARs



Page 29 of 31






on (date)




Page 30 of 31




Step 1

SC Action

Remand SAR

Accept SAR

Reject SAR

Post Request for

SDT Step 2

Appoint SDT








to SPM


Page 31 of 31



Category Vote

SC Action

Board Action

Revise Standard


Direct SDT to Modify

SC Assessment

File for Approval and Implement

Standard

2nd Category Vote



Yes No

Yes

No

SC Forwards to BOD

Step 5

Step 6B Step 6A

Step 7

Step 8


Page 32 of 31



Step 1

SC Action

Remand SAR

Accept SAR

Reject SAR

Post Request for

SDT

Step 2

Appoint SDT










to SPM


Page 33 of 31




SC Action

Revise SAR



SC Assessment



2nd Category Vote


Affirmative


Affirmative

Yes No

Yes

No


Step 5 Step 6B

Step 6A

Step 7

Step 8


No


Yes


Affirmative Yes

A

A


companies

No

B

B

Board Approval

Yes

No

A


Page 34 of 31



Appendix D Ballot Pool Categories For the purposes of category Ballot Pool registration and voting ana person or entity shall register in only one of may join the following categories for each standard that will be voted on (only oneregistered Ballot Pool to vote is allowed peron standards whether or not such person or entity per vote)is a member of ReliabilityFirst A corporation or other organization with integrated operations or with affiliates that qualifies to belong to more than one category (eg Transmission Owners and Load Serving Entities) may join and vote once in each category for which it qualifies provided that each category constitutes a separate membership in the Ballot Body and the organization is represented in each category by a different representative Affiliated entities are collectively limited to one membership in each category in the Ballot Pool for which they are qualified Category 1 ndash Transmission Owner Transmission Operator Transmission Service



Category 5 ndash Distribution Provider Ballot Body Registration Entities may register in the BB at any time during the Standards process The SPM shall review all applications for joining the BB and make a determination of whether they qualify for the self-selection category(ies) In order to comment or vote you must have an active membership in the BB When you submit your registration request to join the BB you are placed in a ldquopending stagerdquo until your account is activated Activation of your account may take up to 24 hours You will be unable to submit comments or join a Ballot Pool until your account is activated The contact designated as primary representative to ReliabilityFirst is the voting member with the secondary contact as the backup Note Registration for a BB is not the same as registration for the compliance registry Although the terminology used to describe the BB categories in most cases has the same




Page 35 of 31



meaning as the terms used in the NERC Functional Model registration in a BB goes beyond the compliance registry in that entities smaller than those stated in the compliance registry guidelines are allowed to register in a BB Entities shall have evidence that they qualify for the BB category they register in Such evidence shall be available for the SPM review to verify BB registration and may include compliance registration Ballot Pool Formation In order to participate in voting on a particular standard an entity must join the Ballot Pool being established for the standard as follows 1 ndash As early as the start of the first posting for comment entities may join one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted 2 - By close of business of the seventh day of the 15 day pre ballot posting period entities wishing to vote must have joined one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted Formatted Tab stops 134 Left

Attachment C Exhibit C to ReliabilityFirst Regional Delegation Agreement

(Redline)


Exhibit C ndash Regional Standard Development Procedure Exhibit C shall set forth the Regional Entityrsquos standards development procedure which NERC agrees meets the following common attributes COMMON ATTRIBUTE 1 Proposed regional reliability standards shall be subject to approval by NERC as the electric reliability organization and by FERC before becoming mandatory and enforceable under Section 215 of the FPA [add reference to any applicable authorities in Canada and Mexico] No regional reliability standard shall be effective within the [Regional Entity Name] area unless filed by NERC with FERC [and applicable authorities in Canada and Mexico] and approved by FERC [and applicable authorities in Canada and Mexico] ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Corporation Reliability Standards Development Procedure (ReliabilityFirst Procedure) Introduction 3rd para (Page 1)

ReliabilityFirst standardsProposed Standards shall be subject to approval by NERC as the electric reliability organization and by the Federal Energy Regulatory Commission (FERC) before becoming mandatory and enforceable under Section 215 of the FPA The approval date of each ReliabilityFirst standard is upon ReliabilityFirst Board approval The effective date will depend on the implementation plan that is provided with each new or revised standard The ReliabilityFirst standard is mandatory and enforceable (without monetary penalties for non-compliance) upon the effective date after ReliabilityFirst Board approval for applicable entities that are members of ReliabilityFirst3 The ReliabilityFirst standard is mandatory and enforceable (with monetary penalties for non-compliance) to all applicable entities within the ReliabilityFirst footprint upon approval by FERC The effective date for non-members upon FERC approval will be determined by the implementation plan that is provided with each new or revised standardNo Standard shall be effective within the ReliabilityFirst area unless filed by NERC with FERC and approved by FERC

COMMON ATTRIBUTE 2 [Regional Entity Name] regional reliability standards shall provide for as much uniformity as possible with reliability standards across the interconnected bulk power system of the North American continent A [Regional Entity Name] reliability standard shall be more stringent than a continent-wide reliability standard including a regional difference that addresses matters that the continent-wide reliability standard does not or shall be a regional difference necessitated by a physical difference in the bulk power system A regional reliability standard that satisfies the statutory and regulatory criteria for approval of proposed North American reliability standards and that is more stringent than a continent-wide reliability standard would generally be acceptable




See ReliabilityFirst Procedure Introduction 4th para (Page 1) ReliabilityFirst Standards shall provide for as much uniformity as possible with NERC reliability standards across the interconnected BPS A ReliabilityFirst Standard shall be more stringent than a NERC reliability standard including a regional difference that addresses matters that the NERC reliability standard does not or shall be a regional difference necessitated by a physical difference in the BPS A ReliabilityFirst Standard that satisfies the statutory and regulatory criteria for approval of proposed NERC reliability standards and that is more stringent than a NERC reliability standard would generally be acceptable

COMMON ATTRIBUTE 3 [Regional Entity Name] regional reliability standards when approved by FERC [add applicable authorities in Canada] shall be made part of the body of NERC reliability standards and shall be enforced upon all applicable bulk power system owners operators and users within the [Regional Entity Name] area regardless of membership in the region ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Introduction 5th para (Page 21)

ReliabilityFirst Standards when approved by FERC shall be made part of the body of NERC reliability standards and shall be enforced upon all applicable BPS owners operators and users within the ReliabilityFirst area regardless of membership in the region

COMMON ATTRIBUTE 4 Requester ⎯ The requester is the sponsor of the regional reliability standard request and may assist in the development of the standard Any member of [Regional Entity Name] or group within [Regional Entity Name] shall be allowed to request that a regional reliability standard be developed modified or withdrawn Additionally any entity (person organization company government agency individual etc) that is directly and materially affected by the reliability of the bulk power system in the [Regional Entity Name] area shall be allowed to request a regional reliability standard be developed modified or withdrawn ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute




See ReliabilityFirst Procedure Roles in the Organizational Standards Development Process Process Roles 1st para - Originator (Page 7)

Originator - Any entity (person organization company government agency individual etc) that is directly and materially affected by the reliability of the ReliabilityFirst BPS is allowed to request a Standard be developed or an existing Standard is modified or deleted by creating a Standards Authorization Request (SAR) See Appendix B

COMMON ATTRIBUTE 5 [Standards or other named] committee ⎯ The [Regional Entity Name] [standards] committee manages the standards development process The [standards] committee will consider which requests for new or revised standards shall be assigned for development (or existing standards considered for deletion) The [standards] committee will advise the [Regional Entity Name] board on standards presented for adoption ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Roles in the Organizational Standards Development Process Process Roles 3rd para - Standards Committee (Page 7) Standards Committee (SC) - The ReliabilityFirst SC will consider which requests for new or revised Standards shall be assigned for development (or existing Standards considered for deletion) The SC manages the Standards development process The SC will advise the ReliabilityFirst Board on Standards presented for adoption by the ReliabilityFirst Board

COMMON ATTRIBUTE 6 [Alternative 6A For a Regional Entity that chooses to vote using a balanced stakeholder committee] The [standards] committee is a balanced stakeholder committee inclusive of all stakeholder interests that provide for or are materially impacted by the reliability of the bulk power system [The [standards] committee votes to approve standards] See Appendix A for the representation model of the [standards] committee ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

ReliabilityFirst did not choose this option ReliabilityFirst chose option 17B 18B and 19B




[Alternative 6B For a Regional Entity that chooses to vote using a balanced ballot body of stakeholders] [Registered ballot body ⎯ The registered ballot body comprises all entities or individuals that qualify for one of the stakeholder segments are registered with [Regional Entity Name] as potential ballot participants in the voting on standards and are current with any designated fees Each member of the registered ballot body is eligible to vote on standards [Each standard action has its own ballot pool formed of interested members of the registered ballot body Each ballot pool comprises those members of the registered ballot body that respond to a pre-ballot survey for that particular standard action indicating their desire to participate in such a ballot pool] The representation model of the registered ballot body is provided in Appendix A] ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Roles in the Regional Reliability Standards Development Process 5th amp 6th para (Page 8) Ballot Body (BB) ndash The Ballot Body comprises all entities that qualify for one or more of the categories and are registered with ReliabilityFirst as potential ballot participants in the voting on standards The categories of registration within the Ballot Body and the registration process are described in Appendix D Ballot Pool ndash The Ballot Pool is comprised of those members of the Ballot Body that register to vote for each particular standard that is up for vote A separate Ballot Pool is established for each standard up for vote Only individuals who have joined the Ballot Pool for that particular standard are eligible to vote on a standard

COMMON ATTRIBUTE 7 [Regional Entity Name] will coordinate with NERC such that the acknowledgement of receipt of a standard request identified in step 1 notice of comment posting period identified in step 4 and notice for vote identified in step 5 below are concurrently posted on both the [Regional Entity Name] and NERC websites ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


ReliabilityFirst will coordinate with NERC such that the acknowledgement of receipt of a standard request identified in step 1 notice of comment posting period identified in step 4 and notice for vote identified in step 5 below are concurrently posted on both the ReliabilityFirst and NERC websites


COMMON ATTRIBUTE 8 An acceptable standard request shall contain a description of the proposed regional reliability standard subject matter containing sufficiently descriptive detail to clearly define the purpose scope impacted parties and other relevant information of the proposed standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete an Organizational Standard 2nd para (Page 10)

The SAR contains a description of the proposed Standard subject matter containing sufficiently descriptive detail to clearly define the purpose scope impacted parties and other relevant information of the proposed Standard The SPM will verify that the submitted SAR form has been adequately completed The SPM may offer the Originator suggestions regarding changes andor improvements to improve clarity and assist the ReliabilityFirst community to understand the Originatorrsquos intent and objectives The Originator is free to accept or reject these suggestions Within 15 days the SPM will electronically acknowledge receipt of the SAR

COMMON ATTRIBUTE 9 Within [no greater than 60] days of receipt of a completed standard request the [standards] committee shall determine the disposition of the standard request ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


See ReliabilityFirst Procedure Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete an Organizational Standard 3rd 4th and 5th para (Page 10)

The SPM will forward theall adequately completed SAR s to the ReliabilityFirst SC at which time the SC will post the SAR for comments within 15 days SARs will be posted and publicly noticed Comments on the SARs will be accepted for a 30-day period from the notice of posting Comments will be accepted online using an internet-based application The SPM will provide a copy of the comments to the Originator and the SC Based on the comments the SC shall make available a consideration of comments report and determine the disposition of the SAR (within 60 calendar days following the SAR commenting period) The disposition decision and decision process shall use the normal ldquobusiness rules and proceduresrdquo of the SC then in effect The SC may take one of the following actions in accordance with the ReliabilityFirst Standards Committee Governance document Within 60 days of receipt of an adequately completed SAR the SC shall determine the disposition of the SAR The disposition decision and decision process shall use the normal ldquobusiness rules and proceduresrdquo of the SC then in effect The SC may take one of the following actions

COMMON ATTRIBUTE 10 The [standards] committee may take one of the following actions

bull Accept the standard request as a candidate for development of a new standard revision of an existing standard or deletion of an existing standard The [standards] committee may at its discretion expand or narrow the scope of the standard request under consideration The [standards] committee shall prioritize the development of standard in relation to other proposed standards as may be required based on the volume of requests and resources

bull Reject the standard request If the [standards] committee rejects a standard request a written explanation for rejection will be delivered to the requester within [no greater than 30] days of the decision

bull Remand the standard request back to the requester for additional work The standards process manager will make reasonable efforts to assist the requester in addressing the deficiencies identified by the [standards] committee The requester may then resubmit the modified standard request using the process above The requester may choose to withdraw the standard request from further consideration prior to acceptance by the [standards] committee






See ReliabilityFirst Procedure Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete an Organizational Standard 6th 7th 8th and 9th para (Page 10 and 110)

bull Accept the SAR as a candidate for development of a new Standard revision of

an existing Standard or deletion of an existing Standard The SC may in its sole discretion expand or narrow the scope of the SAR under consideration The SC shall prioritize the development of SARs as may be required based on the number of SARs under development at any time

bull Reject the SAR If the SC rejects a SAR a written explanation for rejection will be delivered to the Originator within 30 days of the decision


bull Remand the SAR back to the Originator for additional work The SPM will make reasonable efforts to assist the Originator in addressing the deficiencies identified by the SC The Originator may then resubmit the modified SAR using the process above The Originator may choose to withdraw the SAR from further consideration prior to re-submittal to the SC

COMMON ATTRIBUTE 11 Any standard request that is accepted by the [standards] committee for development of a standard (or modification or deletion of an existing standard) shall be posted for public viewing on the [Regional Entity Name] website within [no greater than 30] days of acceptance by the committee ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 1 - Development of a Standards Authorization Request (SAR) to Develop Revise or Delete an Organizational Standard 3rd5th para (Page 110)

Any SAR that is accepted by the SC for development of a Standard (or modification or deletion of an existing Standard) shall be posted for public viewing on the ReliabilityFirst website within no greater than 30 days of acceptance by the SC The status of posted SARs will be publicly posted noted at regularly scheduled (appropriately two weeks) intervals







The standards process manager shall submit the proposed members of the drafting team to the [standards] committee The [standards] committee shall approve the drafting team membership within 60 days of accepting a standard request for development modifying the recommendations of the standards process manager as the committee deems appropriate and assign development of the proposed standard to the drafting team ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 2 ndash Formation of the Standard Drafting Team and Declaration of Milestone Date 1st3rd para (Page 121)

The SPM submits the proposed list of names of the SDT to the SC The SC will either accept the recommendations of the SPM or modify the SDT slate as it deems appropriate within 60 days of accepting a SAR for development

COMMON ATTRIBUTE 13 At the direction from the [standards] committee the standards process manager shall facilitate the posting of the draft standard on the [Regional Entity Name] website along with a draft implementation plan and supporting documents for a no less than a [30]-day comment period The standards process manager shall provide notice to [Regional Entity Name] stakeholders and other potentially interested entities both within and outside of the [Regional Entity Name] area of the posting using communication procedures then currently in effect or by other means as deemed appropriate ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 4 ndash Comment Posting Period 1st para (Page 132)

At the direction from the SC the SPM then facilitates the posting of the draft Standard on the ReliabilityFirst website along with a draft implementation plan and supporting documents for a 30-day comment period The SPM shall also inform ReliabilityFirst Members and other potentially interested entities inside or outside of ReliabilityFirst of the posting using typical membership communication procedures then currently in effect or by other means as deemed appropriate As early as the start of the first posting for comment entities may join one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted The Ballot Pool category description and associated requirements are in Appendix D




The drafting team shall prepare a summary of the comments received and the changes made to the proposed standard as a result of these comments The drafting team shall summarize comments that were rejected by the drafting team and the reason(s) that these comments were rejected in part or whole The summary along with a response to each comment received will be posted on the [Regional Entity Name] website no later than the next posting of the proposed standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 4 ndash Comment Posting Period 3rd para (Page 13) The SDT shall prepare a ldquomodification reportrdquo summarizing the comments received and the changes made as a result of these comments The modification report also summarizes comments that were rejected by the SDT and the reason(s) that these comments were rejected in part or whole Responses to all comments will be posted on the ReliabilityFirst website no later than the next posting of the proposed Standard

COMMON ATTRIBUTE 15 Upon recommendation of the drafting team and if the [standards] committee concurs that all of the requirements for development of the standard have been met the standards process manager shall post the proposed standard and implementation plan for ballot and shall announce the vote to approve the standard including when the vote will be conducted and the method for voting Once the notice for a vote has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 5 ndash Posting for Voting by ReliabilityFirst Membership 1st para (Page 13) Upon recommendation of the SDT and if the SC concurs that all of the requirements for development of the Standard have been met the SPM will post the revised draft Standard implementation plan supporting technical documentation and the ldquomodification reportrdquo Once the notice for a vote has been issued no substantive modifications may be made to the proposed standard unless the revisions are posted and a new notice of the vote is issued





The standards process manager shall schedule a vote by the [Regional Entity Name] [registered ballot body[standards] committee] The vote shall commence no sooner than [15] days and no later than [30] days following the issuance of the notice for the vote ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 5 ndash Posting for Voting by ReliabilityFirst Membership 3rd para (Page 13)

By 1159 PM Central Prevailing Time (CPT) of the seventh day of the 15 day pre- ballot posting period registered BB membersentities intending to vote on the proposed standard must have joined one of the five categories of the Ballot Pool established for the eventual voting on the proposed standard being posted The SPM will schedule a Vote by the Ballot Pool which is to be scheduled to commence no sooner than 15 days and no later than 30 days following this posting The Vote by the Ballot Pool is an advisory to the ReliabilityFirst Board

COMMON ATTRIBUTE 17 [Alternative 17A For an RE that chooses to vote using a balanced stakeholder committee] The [standards] committee shall give due consideration to the work of the drafting team as well as the comments of stakeholders and minority objections in approving a proposed regional reliability standard for submittal to the [Regional Entity Name] board The [standards] committee may vote to approve or not approve the standard Alternatively the [standards] committee may remand the standard to the drafting team for further work or form a new drafting team for that purpose ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute ReliabilityFirst did not choose this option ReliabilityFirst chose option 17B 18B and 19B [Alternative 17B For an RE that chooses to vote using a balanced ballot body of stakeholders] The [Regional Entity Name] registered ballot body shall be able to vote on the proposed standard during a period of [not less than 10] days ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute




The Ballot Pool shall be allowed to vote over a period of 15 days It is expected that vVotes will be submitted electronically but may be submitted through other means as approved by the SC

COMMON ATTRIBUTE 18 [Alternative 18A For an RE that chooses to vote using a balanced stakeholder committee] The [standards] committee may not itself modify the standard without issuing a new notice to stakeholders regarding a vote of the modified standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

ReliabilityFirst did not choose this option ReliabilityFirst chose option 17B 18B and 19B [Alternative 18B For an RE that chooses to vote using a balanced ballot body of stakeholders] All members of [Regional Entity Name] are eligible to participate in voting on proposed new standards standard revisions or standard deletions [Alternatively Each standard action requires formation of a ballot pool of interested members of the registered ballot body] ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


All entities registered as part of the BB members are eligible to participate in voting on proposed new Standards Standard revisions or Standard deletions There is a requirement to separately join a Ballot Pool to participate in voting for each standard Each entity can join only in one category of the Ballot Pool and shall have one vote The voting results will be composed of only the votes from BB entities that have joined the Ballot Pool for the standard being voted on and responding within the 15 day voting period Votes may be accompanied by comments explaining the vote but are not required All comments shall be responded to and posted to the ReliabilityFirst website prior to going to the SC or Board

COMMON ATTRIBUTE 19 [Alternative 19A For an RE that chooses to vote using a balanced stakeholder committee]


Formatted Font 12 pt Not Italic


Actions by the committee shall be recorded in the regular minutes of the committee ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

ReliabilityFirst did not choose this option ReliabilityFirst chose option 17B 18B and 19B [Alternative 19B For an RE that chooses to vote using a balanced ballot body of stakeholders] Approval of the proposed regional reliability standard shall require a [two thirds] majority in the affirmative (affirmative votes divided by the sum of affirmative and negative votes) Abstentions and non-responses shall not count toward the results except that abstentions may be used in the determination of a quorum A quorum shall mean [XX] of the members of the [registered ballot bodyballot pool] submitted a ballot ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 6A ndash Membership Voting Receives Two-Thirds or GreaterSimple Majority of Affirmative Category Votes 1st para (Page 14) A two-thirds or greater simple majority1 of votes within a category determines the vote for that category The Initial ballot has passed ifIf there is a two-thirds or greatersimple affirmative majority of category votes (only those categories with votes cast will be considered) during the 15-day voting period and a quorum2 is met (a quorum consists of a simple majority of individuals who have joined the Ballot Pool) the SC will forward the Standard to the ReliabilityFirst Board for action (Step 7)

COMMON ATTRIBUTE 20 Under no circumstances may the board substantively modify the proposed regional reliability standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute




See ReliabilityFirst Procedure Step 7 ndash Action by the ReliabilityFirst Board of Directors5th 3rd para (Page 165)

bull Approve the draft Standard action with only minor or no modification Under

no circumstances may the Board substantively modify the proposed regional reliability standard

COMMON ATTRIBUTE 21 Once a regional reliability standard is approved by the board the standard will be submitted to NERC for approval and filing with FERC [and applicable authorities in Canada and Mexico] ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute

See ReliabilityFirst Procedure Step 7 ndash Action by the ReliabilityFirst Board of Directors 6th5th para (Page 176) Once a regional ReliabilityFirst Standard is approved by the Board the standard will be submitted to NERC for approval and filing with FERC


bull Open - Participation in the development of a regional reliability standard shall be open to all organizations that are directly and materially affected by the [Regional Entity Name] bulk power system reliability There shall be no undue financial barriers to participation Participation shall not be conditioned upon membership in [Regional Entity Name] and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements Meetings of drafting teams shall be open to the [Regional Entity Name] members and others


See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 3rdd para - Openness (Page 9)

Openness - Participation is open to all Organizations who are directly and materially affected by the ReliabilityFirst region BPS reliability There shall be no undue financial barriers to participation Participation shall not be conditioned upon membership in the ReliabilityFirst and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements Meetings of SDTs are open to the ReliabilityFirst membership and to others






bull Balanced - The [Regional Entity Name] standards development process strives to have an appropriate balance of interests and shall not be dominated by any two interest categories and no single interest category shall be able to defeat a matter


See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 4th para - Balance (Page 9)

Balanced - The ReliabilityFirst standards development process strives to have an appropriate balance of interests and shall not be dominated by any two interest categories and no single interest category shall be able to defeat a matter


bull Inclusive mdash Any entity (person organization company government agency individual etc) with a direct and material interest in the bulk power system in the [Regional Entity Name] area shall have a right to participate by a) expressing a position and its basis b) having that position considered and c) having the right to appeal


See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 5th para - Inclusive (Page 9)

Inclusive - Any entity (person organization company government agency individual etc) with a direct and material interest in the BPS in the ReliabilityFirst area shall have a right to participate by a) expressing a position and its basis b) having that position considered and c) having the right to appeal


bull Fair due process mdash The regional reliability standards development procedure shall provide for reasonable notice and opportunity for public comment At a minimum the procedure shall include public notice of the intent to develop a standard a public comment period on the proposed standard due consideration of those public comments and a ballot of interested stakeholders





See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 2nd para - Due process (Page 8)

Fair due process - The ReliabilityFirst standards development process shall provide for reasonable notice and opportunity for public comment At a minimum the procedure shall include public notice of the intent to develop a standard a public comment period on the proposed standard due consideration of those public comments and a ballot of interested stakeholders


bull Transparent mdash All actions material to the development of regional reliability standards shall be transparent All standards development meetings shall be open and publicly noticed on the regional entityrsquos Web site


See ReliabilityFirst Procedure ReliabilityFirst Corporation Organizational Standard Development Process Assumptions and Prerequisites 6th para - Transparent (Page 9)

Transparent - All actions material to the development of ReliabilityFirst Standards shall be transparent All standards development meetings shall be open and publicly noticed on ReliabilityFirstrsquos Web site


bull Does not unnecessarily delay development of the proposed reliability standard ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


Does not unnecessarily delay development of the proposed Standard

COMMON ATTRIBUTE 28 Each standard shall enable or support one or more of the reliability principles thereby ensuring that each standard serves a purpose in support of the reliability of the regional bulk power system Each standard shall also be consistent with all of the reliability principles thereby ensuring that no standard undermines reliability through an unintended consequence







Each standard shall enable or support one or more of the reliability principles thereby ensuring that each standard serves a purpose in support of the reliability of the regional BPS Each standard shall also be consistent with all of the reliability principles thereby ensuring that no standard undermines reliability through an unintended consequence

COMMON ATTRIBUTE 29 While reliability standards are intended to promote reliability they must at the same time accommodate competitive electricity markets Reliability is a necessity for electricity markets and robust electricity markets can support reliability Recognizing that bulk power system reliability and electricity markets are inseparable and mutually interdependent all regional reliability standards shall be consistent with NERCrsquos market interface principles Consideration of the market interface principles is intended to ensure that standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets ReliabilityFirstrsquos regional standard development procedure or other governing documents contain the following language relative to this Common Attribute


While ReliabilityFirst Standards are intended to promote reliability they must at the same time accommodate competitive electricity markets Reliability is a necessity for electricity markets and robust electricity markets can support reliability Recognizing that BPS reliability and electricity markets are inseparable and mutually interdependent all ReliabilityFirst Standards shall be consistent with NERCrsquos market interface principles Consideration of the market interface principles is intended to ensure that standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets

COMMON ATTRIBUTE 30 To ensure uniformity of regional reliability standards a regional reliability standard shall consist of the elements identified in this section of the procedure These elements are intended to apply a systematic discipline in the development and revision of standards This discipline is necessary to achieving standards that are measurable enforceable and consistent







COMMON ATTRIBUTE 31 All mandatory requirements of a regional reliability standard shall be within the standard Supporting documents to aid in the implementation of a standard may be referenced by the standard but are not part of the standard itself



COMMON ATTRIBUTE 32 Applicability Clear identification of the functional classes of entities

responsible for complying with the standard noting any specific additions or exceptions If not applicable to the entire [Regional Entity Name] area then a clear identification of the portion of the bulk power system to which the standard applies Any limitation on the applicability of the standard




based on electric facility requirements should be described


See ReliabilityFirst Manual Format Requirements of an Organizational Standard Organizational Standard Format Requirement Template Row 3 - Applicability (Page 4) Applicability

Clear identification of the functional classes of entities responsible for complying with the Standard noting any specific additions or exceptions If not applicable to the entire ReliabilityFirst area then a clear identification of the portion of the BPS to which the Standard applies Any limitation on the applicability of the Standard based on electric facility requirements should be described

COMMON ATTRIBUTE 33 Measure(s) Each requirement shall be addressed by one or more

measures Measures are used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measure will identify to whom the measure applies and the expected level of performance or outcomes required demonstrating compliance Each measure shall be tangible practical and as objective as is practical It is important to realize that measures are proxies to assess required performance or outcomes Achieving the measure should be a necessary and sufficient indicator that the requirement was met Each measure shall clearly refer to the requirement(s) to which it applies


See ReliabilityFirst Procedure Format Requirements of an Organizational Standard Organizational Standard Format Requirement Template Row 8 - Measures (Page 5)


Measure(s)

Each requirement shall be addressed by one or more measurements Measurements that will be used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above Each measurement identifies to whom the measurement applies Each measurement shall be tangible practical and as objective as is practical Achieving the full compliance level of each measurement should beis a necessary and sufficient indicator that the requirement was met

COMMON ATTRIBUTE 34 Compliance Monitoring Process

Defines for each measure bull The specific data or information that is required to

measure performance or outcomes bull The entity that is responsible for providing the data

or information for measuring performance or outcomes

bull The process that will be used to evaluate data or information for the purpose of assessing performance or outcomes



bull Measurement data retention requirements and assignment of responsibility for data archiving


See ReliabilityFirst Procedure Format Requirements of an Organizational Standard Compliance Administration Elements Row 1 - Compliance Monitoring Process (Page 6)


Defines for each measure bull The specific data or information that is

required to measure performance or outcomes

bull The entity that is responsible to provide the data or information for measuring


performance or outcomes bull The process that will be used to evaluate

data or information for the purpose of assessing performance or outcomes



bull Measurement dData retention requirements and assignment of responsibility for data archiving

bull Violation severity levels

116-390 Village Blvd Princeton NJ 08540 6094528060 | wwwnerccom

Comment Period Opens for Proposed Amendments to NERC Rules of Procedure Appendices 3B and 3D Comments Due April 15 2011 NERC is herby requesting comments on two proposed revisions to the NERC Rules of Procedure to amend Appendix 3B Election Procedure for Members of NERC Standards Committee and to add Appendix 3D Registered Ballot Body Criteria The proposed Appendices 3B and 3D are being posted for a forty-five day comment period that will close on April 15 2011 NERC Management plans on presenting these proposed changes to the NERC Board of Trustees for approval at the May 11 2011 Board of Trustees meeting Appendix 3B Election Procedure for Members of NERC NERC is requesting public comments on the proposed changes to the Procedure for Election of Members of the NERC Standards Committee (ldquoSC Election Procedurerdquo) which is included in the NERC Rules of Procedure as Appendix 3B There are three proposed substantive changes to the SC Election Procedure

1) The first proposed change would require the chairman and vice chairman to serve as non-voting members of the Standards Committee The purpose of this change is to clarify that the Standard Committeersquos officers are expected to act in support of the electric reliability organization rather than in support of any particular industry segment

2) The second proposed change would require a Canadian representative on the Standards Committee to be any company or association incorporated in Canada any agency of a federal provincial or local government in Canada or any person with Canadian citizenship who is residing in Canada

3) The third proposed change simplifies the process of filling vacant Standards Committee positions by eliminating the need to collect petitions and hold a ratification vote

Other minor conforming changes are also being proposed to Appendix 3B Appendix 3D Registered Ballot Body Criteria On September 3 2010 the Federal Energy Regulatory Commission (ldquoFERCrdquo) approved NERCrsquos Standard Processes Manual to replace the previous FERC approved Reliability Standards Development Procedure Version 7 which was included as Appendix 3A to the NERC Rules of Procedure The Reliability Standards Development Procedure Version 7 included the

-2-

Registered Ballot Body Criteria as part of the Rules of Procedure However the new Standard Processes Manual excluded the Registered Ballot Body criteria NERC has determined that these criteria need to be reincorporated into the NERC Rules of Procedure NERC is proposing to include the Registered Ballot Body Criteria as a new Appendix 3D Registered Ballot Body Criteria The proposed criteria are included with this posting for comment In addition to clarifying changes the proposed changes include the following

1) Individuals are added to the criteria of potential Registered Ballot Body members

2) In the Segment Qualification Guidelines clarification was added that individuals or entities that elect to participate in Segment 8 are not eligible to participate in multiple segments

3) In the Segment Qualification Guidelines clarification was added to state that after

members of each segment are selected registered participants may apply to change these segments annually on a schedule determined by the Standards Committee

4) Several places in the criteria were clarified to include ISOs to those areas that were

previously limited to RTOs 5) A new criterion was added to Segment 3 allowing agents or associations to represent

groups of LSEs 6) Segment 5 was clarified to include variable and other renewable resources 7) A new criterion was added to Segment 5 allowing agents or associations to represent

groups of electric generators 8) A new criterion was added to Segment 6 allowing agents or associations to represent

groups of electricity brokers aggregators or marketers Segment 6 also adds a provision that this segment includes demand-side management providers

9) Segment 8 was clarified to include a provision that individuals or entities such as

consultants or vendors providing products or services related to bulk power system reliability within the previous 12 months to another entity eligible to joint Segments 1 through 7 (and therefore eligible to join one of those segments) are not eligible to join Segment 8

10) Regional reliability organizations were replaced in Segment 10 with regional entities

Submission of Comments Comments are due April 15 2011 and must be submitted electronically to ropcommentsnercnet NERC intends to submit these proposed Rule of Procedure changes to the NERC Board of Trustees for approval at its May 11 2011 meeting For additional information please contact Elizabeth Heenan at elizabethheenannercnet


Procedures for Election of Members of the Standards Committee (CLEAN)

PPrroocceedduurreess ffoorr EElleeccttiioonn ooff MMeemmbbeerrss ooff tthhee SSttaannddaarrddss CCoommmmiitttteeee

Appendix 3B






Purpose 4




















1 Industry stakeholder Segment criteria and a list of entities in the NERC Standards Registered Ballot Body are provided on the NERC web site In this procedure the term ldquoSegmentrdquo shall mean one of the currently defined industry stakeholder Segments





Standards Committee Officers Approximately 90 days prior to the end of each term the Standards Committee shall elect a chairman and vice chairman to serve as officers and preside over the business of the committee for the following year The officers shall serve a term of one year without limit on the number of terms an officer may serve although the setting of limits in the future is not precluded The chairman and vice chairman shall serve as non-voting members of the Standards Committee The SPM serves as a non-voting member and secretary of the Standards Committee


Segment Representative Nominations Approximately 90 days prior to the start of each term the SPM shall request nominations to fill Standards Committee positions that will become open with the expiration of the current term Notice of the nominations process shall be announced to the Registered Ballot Body and to others that may be interested in standards for the reliability of North American bulk electric systems The SPM shall post the announcement on the NERC web page and distribute the announcement to applicable NERC e-mail lists The announcement shall include a brief description of the responsibilities of the Standards Committee and estimates of the work effort and travel expected of Standards Committee members Any person or entity may submit a nomination Self-nominations are encouraged To be eligible for nomination a nominee shall be an employee or agent of an entity registered in the applicable Segment To allow verification of affiliation a nominee shall be a registered User in the NERC Registered Ballot Body It is not required that the nominee be the same person as the entityrsquos Registered Ballot Body representative for that Segment


The SPM shall provide a method for the submittal of nominations preferably an on-line nominations form using Internet protocols The nomination form shall request the following information and other information that the SPM deems necessary to completing the election process











Segment Representative Elections The SPM shall prepare a slate of nominees for each Segment The Segment slate shall consist of all valid nominations received for that Segment without prejudice in the method of listing the slate The SPM shall provide an electronic ballot form for each Segment listing the slate of nominees Each Registered Ballot Body entity in a Segment may cast one vote per Standards Committee member position being filled (ie one vote if one position is being filled and two votes if two 3 Information items 3ndash5 are provided automatically from the nominee during registration


positions are being filled) In the case that an entity casts two votes within a Segment each vote must be for a different candidate in that Segment (ie an entity cannot vote twice for a nominee within a Segment) This ballot procedure is repeated for each Segment in which an entity is a member of the Registered Ballot Body The ballot for each Segment is conducted independently from the ballots of other Segments Only the entities in the Registered Ballot Body for a Segment may vote in that Segment The ballot period shall be announced to the Registered Ballot Body and to others that may be interested in standards for the reliability of North American bulk electric systems The SPM shall post the announcement on the NERC web page and distribute the announcement to applicable NERC e-mail lists The ballot period shall remain open for ten calendar days from the announced opening of the ballot period at which time the ballot period shall be closed Votes may be cast by the Registered Ballot Body Representative for each entity or a proxy designated by the representative An entity may vote in each Segment in which it is registered Ballot results shall remain confidential during the ballot period As soon as practical after the close of the ballot period the SPM shall publicly post the election results for each Segment (ie the names of elected members and slates for any run-off elections that may be required)



In the event that the election is incomplete in a Segmentrsquos first ballot (no candidate or only one candidate meets the criteria) then a second ballot will be conducted in that Segment using a process similar to that previously described If two positions are remaining to be filled in the second ballot the slate of candidates shall consist of the four candidates receiving the highest number of votes in the first ballot If one position is remaining to be filled in the second ballot the slate shall consist of the two candidates receiving the highest number of votes A candidate who was elected in the first ballot is considered elected and is excluded from the second ballot In the event of a tie that precludes choosing the top four (or two) candidates the slate will be expanded to include those candidates that are tied After the second ballot in the Segment the candidate(s) receiving the highest number of votes shall be elected to fill the remaining position(s) in that Segment 4 Each entity in the Segment is allowed to cast two votes This criterion means that more than fifty percent (gt50) of the entities cast one of their votes for that nominee


In the event of a tie between two or more candidates after a second ballot a run-off ballot may be used to break the tie The position shall remain vacant until the tie is broken by the Segment







Special Elections

The Standards Committeersquos officers shall determine the need for a special election to fill a vacant Standards Committee position between regular elections considering among other things the timing of the last and the next regular election If a need is determined the Standards Committee officers shall communicate a request to the Director of Standards who shall initiate a process to conduct the election The SPM shall post a request for nominations on the NERC web page and distribute the announcement to applicable NERC e-mail lists eg the ballot body of the Segment(s) involved The election will be held 30 days after the announcement and shall use the same election process and formula employed in regular elections The Board of Trustees shall be notified of the election results



Procedures for Election of Members of the Standards Committee (REDLINE)

PPrroocceedduurreess ffoorr EElleeccttiioonn Procedure for ooff MMeemmbbeerrss ooff tthhee NERC SSttaannddaarrddss CCoommmmiitttteeee

Appendix 3B



Effective January 18 2007




Purpose 4





















1 Industry stakeholder Segment criteria and a list of entities in the NERC Standards Registered Ballot Body are provided aton the NERC website and in Appendix 3D to the NERC Rules of Procedure In this procedure the term ldquoSegmentrdquo shall mean one of the currently defined industry stakeholder Segments






Standards Committee Officers At the beginning of each annual Approximately 90 days prior to the end of each term the Standards Committee shall as a first order of business elect a chairman and vice chairman to serve as officers and preside over the business of the committee for the following year The officers shall serve a term of one year without limit on the number of terms an officer may serve although the setting of limits in the future is not precluded The chairman and vice chairman shall serve as non-voting members of the Standards Committee The SPM serves as a non-voting member and secretary of the Standards Committee


Segment Representative Nominations Approximately 90 days prior to the start of each term the SPM shall request nominations to fill Standards Committee positions that will become open with the expiration of the current term Notice of the nominations process shall be announced to the Registered Ballot Body and to others that may be interested in standards for the reliability of North American bulk electric systems The SPM shall post the announcement on the NERC web page and distribute the announcement to applicable NERC e-mail lists The announcement shall include a brief description of the responsibilities of the Standards Committee and estimates of the work effort and travel expected of Standards Committee members Any person or entity may submit a nomination Self-nominations are encouraged To be eligible for nomination a nominee shall be an employee or agent of an entity registered in the applicable Segment To allow verification of affiliation a nominee shall be a registered User



in the NERC Registered Ballot Body It is not required that the nominee be the same person as the entityrsquos Registered Ballot Body representative for that Segment The SPM shall provide a method for the submittal of nominations preferably an on-line nominations form using Internet protocols The nomination form shall request the following information and other information that the SPM deems necessary to completing the election process











Segment Representative Elections The SPM shall prepare a slate of nominees for each Segment The Segment slate shall consist of all valid nominations received for that Segment without prejudice in the method of listing the slate

3 Information items 3ndash5 are provided automatically from the nominee during registration



The SPM shall provide an electronic ballot form for each Segment listing the slate of nominees Each Registered Ballot Body entity in a Segment may cast one vote per Standards Committee member position being filled (ie one vote if one position is being filled and two votes if two positions are being filled) In the case that an entity casts two votes within a Segment each vote must be for a different candidate in that Segment (ie an entity cannot vote twice for a nominee within a Segment) This ballot procedure is repeated for each Segment in which an entity is a member of the Registered Ballot Body The ballot for each Segment is conducted independently from the ballots of other Segments Only the entities in the Registered Ballot Body for a Segment may vote in that Segment The ballot period shall be announced to the Registered Ballot Body and to others that may be interested in standards for the reliability of North American bulk electric systems The SPM shall post the announcement on the NERC web page and distribute the announcement to applicable NERC e-mail lists The ballot period shall remain open for ten calendar days from the announced opening of the ballot period at which time the ballot period shall be closed Votes may be cast by the Registered Ballot Body Representative for each entity or a proxy designated by the representative An entity may vote in each Segment in which it is registered Ballot results shall remain confidential during the ballot period As soon as practical after the close of the ballot period the SPM shall publicly post the election results for each Segment (ie the names of elected members and slates for any run-off elections that may be required)



In the event that the election is incomplete in a Segmentrsquos first ballot (no candidate or only one candidate meets the criteria) then a second ballot will be conducted in that Segment using a process similar to that previously described If two positions are remaining to be filled in the second ballot the slate of candidates shall consist of the four candidates receiving the highest number of votes in the first ballot If one position is remaining to be filled in the second ballot the slate shall consist of the two candidates receiving the highest number of votes A candidate who was elected in the first ballot is considered elected and is excluded from the second ballot In the event of a tie that precludes choosing the top four (or two) candidates the slate will be expanded to include those candidates that are tied

4 Each entity in the Segment is allowed to cast two votes This criterion means that more than fifty percent (gt50) of the entities cast one of their votes for that nominee



After the second ballot in the Segment the candidate(s) receiving the highest number of votes shall be elected to fill the remaining position(s) in that Segment In the event of a tie between two or more candidates after a second ballot a run-off ballot may be used to break the tie The position shall remain vacant until the tie is broken by the Segment







Special Elections Between regularly scheduled elections a Segment may hold a special election to replace an existing member or fill a vacant position A special election request may be requested by petition of ten entities or 25 of the entities registered in a Segment whichever is less It is the responsibility of the requester(s) to collect the requisite number of signatories to the petition and submit it to the SPM If SPM receives a valid petition for a special election the SPM shall request that the Segment ratify the need for a special election Ratification requires approval by a two-thirds majority of the entities registered in the Segment If the request is ratified by the Segment the SPM shall initiate the request for nominations and election as described later in this procedure

The Standards Committeersquos officers shall determine the need for a special election to fill a vacant Standards Committee position between regular elections considering among other things the timing of the last and the next regular election If a need is determined the Standards Committee officers shall communicate a request to the Director of Standards who shall initiate a process to conduct the election The SPM shall post a request for nominations on the NERC web



page and distribute the announcement to applicable NERC e-mail lists eg the ballot body of the Segment(s) involved The election will be held 30 days after the announcement and shall use the same election process and formula employed in regular elections The Board of Trustees shall be notified of the election results




Ballot Body (CLEAN)

AAppppeennddiixx 33DD mdashmdash DDeevveellooppmmeenntt ooff tthhee RReeggiisstteerreedd BBaalllloott BBooddyy1


1

The Registered Ballot Body comprises all organizations entities and individuals that




Each participant when initially registering to join the Registered Ballot Body and annually thereafter shall self-select to belong to one of the segments described below






3 At any given time affiliated entities may collectively be registered only once within a segment

4 Any individual or entity such as a consultant or vendor providing products or services related to bulk power system reliability within the previous 12 months to another entity eligible to join Segments 1 through 7 shall be qualified to join any one segment for which one of the entities receiving those products or services is qualified to join

5 Corporations organizations entities and individuals may participate freely in all subgroups

6 After their initial selection registered participants may apply to change segments annually on a schedule determined by the Standards Committee

7 The qualification guidelines and rules for joining segments will be reviewed periodically to ensure that the process continues to be fair open balanced and inclusive Public input will be solicited in the review of these guidelines

8 Since all balloting of standards will be done electronically any registered participant may designate a proxy to vote on its behalf There are no limits on how many proxies a person may hold However NERC must have in its possession either in writing or by email documentation that the voting right by proxy has been transferred

1 The segment qualification guidelines were proposed in the final report of the NERC Standing Committees Representation Task Force on February 7 2002 The Board of Trustees endorsed the industry segments and weighted segment voting model on February 20 2002 and may change the model from time to time

Segments





d Excludes RTOs and ISOs that are eligible to join to Segment 2 Segment 2 Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)




c Agents or associations can represent groups of LSEs Segment 4 Transmission Dependent Utilities (TDUs)




b A corporation that sets up separate corporate entities for each one or two generating plants in which it is involved may only have one vote in this segment regardless of how many single-plant or multiple-plant corporations the parent corporation has established or is involved in

c Agents or associations can represent groups of electrical generators Segment 6 Electricity Brokers Aggregators and Marketers













d Any entity or person currently employed by an entity that is eligible to join one or more of the other nine segments shall not be qualified to join Segment 8

e Any individual or entity such as a consultant or vendor providing products or services related to bulk power system reliability within the previous 12 months to another entity eligible to join Segments 1 through 7 shall be qualified to join any one segment for which one of the entities receiving those products or services is qualified to join and shall not be eligible to join segment 8



b May include public utility commissions Segment 10 Regional Entities

a Any entity that is a regional entity as defined in NERCrsquos Bylaws It is recognized that there may be instances in which an entity is both an RTO or ISO and a regional entity In such a case the two functions must be sufficiently independent to meet NERCrsquos Rules of Procedure and applicable regulatory requirements as evidenced by the approval of a regional entity delegation agreement Without such an approval the entity shall be limited to choosing to enter one segment or the other but not both



Ballot Body (REDLINE)

AAppppeennddiixx 33DDBB mdashmdash DDeevveellooppmmeenntt ooff tthhee RReeggiisstteerreedd BBaalllloott BBooddyy1


1

The Registered Ballot Body comprises all organizations and entities and individuals that




Each participant when initially registering to join the Registered Ballot Body and annually thereafter will shall self-select to belong to one of the segments described abovebelow





The general guidelines for all segments are


2 3 At any given time affiliated entities may collectively be registered only once within a segment

3 4 Any person individual or entity such as a consultant or vendor providing products or services related to bulk

power system reliability within the previous 12 months to another entity eligible to join Segments 1 tothrough 7 shall be qualified to join any one segment for which one of the entities receiving those products or services is qualified to join

4 5 Corporations organizations and entities and individuals may participate freely in all subgroups

5

1 The segment qualification guidelines were proposed in the final report of the NERC Standing Committees Representation Task Force on February 7 2002 The Board of Trustees endorsed the industry segments and weighted segment voting model on February 20 2002 and may change the model from time to time The latest version (approved or endorsed by the NERC Board of Trustees) shall be used in the NERC Reliability Standards Development Procedure

6 After their initial selection registered participants may apply to change segments annually according to a defined scheduleon a schedule determined by the Standards Committee

6 7 The qualification guidelines and rules for joining segments will be reviewed periodically to ensure that the

process continues to be fair open balanced and inclusive Public input will be solicited in the review of these guidelines

7 8 Since all balloting of standards will be done electronically any registered participant may designate a proxy to

vote on its behalf There are no limits on how many proxies a person may hold However NERC must have in its possession either in writing or by email documentation that the voting right by proxy has been transferred

Segments





d Excludes RTOs and ISOs (that are eligible to join to Segment 2) Segment 2 Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs)




bc Agents or associations can represent groups of LSEs Segment 4 Transmission Dependent Utilities (TDUs)




b A corporation that sets up separate corporate entities for each one or two generating plants in which it is involved may only have one vote in this segment regardless of how many single-plant or twomultiple-plant corporations the parent corporation has established or is involved in

bc Agents or associations can represent groups of electrical generators

Segment 6 Electricity Brokers Aggregators and Marketers













d Any entity or person currently employed by an entity that is eligible to join one or more of the other eight nine segments shall not be qualified to join Segment 8

de Any individual or entity such as a consultant or vendor providing products or services related to bulk power system reliability within the previous 12 months to another entity eligible to join Segments 1 through 7 shall be qualified to join any one segment for which one of the entities receiving those products or services is qualified to join and shall not be eligible to join segment 8



b May include public utility commissions Segment 10 Regional Reliability Organizations and Regional Entities

a Any entity that is a regional reliability organization or regional entity as defined in NERCrsquos Bylaws It is recognized that there may be instances in which an entity is both an RTO or ISO and a regional entity or regional reliability organization In such a case the two functions must be sufficiently independent to meet NERCrsquos Rules of Procedure and applicable regulatory requirements as evidenced by the approval of a regional entity delegation agreement Without such an approval the entity shall be limited to choosing to enter one segment or the other but not both

From Guy V ZitoTo rscSubject FW Comment Period Opens for Proposed Changes to NERC Rules of Procedure Appendices 3B and 3DDate Tuesday March 01 2011 72758 PM

RSC Members Lets discuss at the next RSC meeting-Lee please add to our agenda I believe the proposed changes to the NERC SC election procedureare beneficial in addressing some issues that have been expressed by our members Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Elizabeth Heenan [ElizabethHeenannercnet]Sent Tuesday March 01 2011 605 PMTo Elizabeth HeenanSubject Comment Period Opens for Proposed Changes to NERC Rules of Procedure Appendices 3B and 3D

Comment Period Opens for Proposed Changes to NERC Rules of ProcedureAppendices 3B and 3D

NERC Stakeholders

Now available at httpwwwnerccomfilesFinal_Posting_Appendices_3B_3D_2011030120(3)pdf

NERC is requesting comments on two proposed revisions to the NERC Rules of Procedure to amend Appendix 3B Election Procedure forMembers of NERC Standards Committee and to add Appendix 3D Registered Ballot Body Criteria NERC is requesting public comments onthe proposed changes to the Procedure for Election of Members of the NERC Standards Committee (ldquoSC Election Procedurerdquo) which isincluded in the NERC Rules of Procedure as Appendix 3B NERC is also proposing to include the Registered Ballot Body Criteria as a newAppendix 3D Registered Ballot Body Criteria The proposed Appendices 3B and 3D are being posted for a forty-five day comment periodthat will close on April 15 2011 NERC Management plans on presenting these proposed changes to the NERC Board of Trustees forapproval at the May 11 2011 Board of Trustees meeting

Submission of Comments

Comments are due April 15 2011 and must be submitted electronically to ropcommentsnercnet NERC intends to submit theseproposed Rule of Procedure changes to the NERC Board of Trustees for approval at its May 11 2011 meeting




6094528060 | wwwnerccom ---You are currently subscribed to nercroster as gzitonpccorgTo unsubscribe send a blank email to leave-1249746-3920898eac8c94409e17058b6e89bfa4b2626listservnerccom



Note from the Project 2010-07 SDT The redline changes included in this document are the work of the Project 2010-07 SDT and are provided as a companion to the teamrsquos White Paper the aim is to provide an example to convey the direction of our proposal This is not intended to be a comprehensive rewrite of the standard

A Introduction

1 Title Facility Connection Requirements

2 Number FAC-001-0

3 Purpose To avoid adverse impacts on reliability Transmission Bulk Electric System Facility Oowners must establish facility connection and performance requirements

4 Applicability

41 Transmission Owner

4142 Generator Owner

5 Effective Date April 1 2005

B Requirements

R1 The Transmission Owner shall document maintain and publish facility connection requirements to ensure compliance with NERC Reliability Standards and applicable Regional Reliability Organization subregional Power Pool and individual Transmission Owner planning criteria and facility connection requirements The Transmission Ownerrsquos facility connection requirements shall address connection requirements for

R11 Generation facilities

R12 Transmission facilities and

R13 End-user facilities

R2 The Transmission Ownerrsquos facility connection requirements shall address but are not limited to the following items

R21 Provide a written summary of its plans to achieve the required system performance as described above throughout the planning horizon

R211 Procedures for coordinated joint studies of new facilities and their impacts on the interconnected transmission systems

R212 Procedures for notification of new or modified facilities to others (those responsible for the reliability of the interconnected transmission systems) as soon as feasible

R213 Voltage level and MW and MVAR capacity or demand at point of connection

R214 Breaker duty and surge protection

R215 System protection and coordination

R216 Metering and telecommunications

R217 Grounding and safety issues



R218 Insulation and insulation coordination

R219 Voltage Reactive Power and power factor control

R2110 Power quality impacts

R2111 Equipment Ratings

R2112 Synchronizing of facilities

R2113 Maintenance coordination

R2114 Operational issues (abnormal frequency and voltages)

R2115 Inspection requirements for existing or new facilities

R2116 Communications and procedures during normal and emergency operating conditions

R3 The Transmission Owner shall maintain and update its facility connection requirements as required The Transmission Owner shall make documentation of these requirements available to the users of the transmission system the Regional Reliability Organization and NERC on request (five business days)


R3

C Measures


M2 The Transmission Owner shall make available (to its Compliance Monitor) for inspection evidence that it met all requirements stated in Reliability Standard FAC-001-0_R2


M3M4 The Generator Owner that receives an interconnection request for its facility shall make available (to its Compliance Monitor) for inspection evidence that it met the requirements stated in Reliability Standard FAC-001-0 R4

D Compliance

1 Compliance Monitoring Process

11 Compliance Monitoring Responsibility

Compliance Monitor Regional Reliability Organization

12 Compliance Monitoring Period and Reset Timeframe

On request (five business days)

13 Data Retention

Formatted Indent Left 035 No bullets ornumbering



None specified


None

2 Levels of Non-Compliance

21 Level 1 Facility connection requirements were provided for generation transmission and end-user facilities per Reliability Standard FAC-001-0_R1 but the document(s) do not address all of the requirements of Reliability Standard FAC-001-0_R2

22 Level 2 Facility connection requirements were not provided for all three categories (generation transmission or end-user) of facilities per Reliability Standard FAC-001-0_R1 but the document(s) provided address all of the requirements of Reliability Standard FAC-001-0_R2

23 Level 3 Facility connection requirements were not provided for all three categories (generation transmission or end-user) of facilities per Reliability Standard FAC-001-0_R1 and the document(s) provided do not address all of the requirements of Reliability Standard FAC-001-0_R2

24 Level 4 No document on facility connection requirements was provided per Reliability Standard FAC-001-0_R3

E Regional Differences

1 None identified

Version History

Version Date Action Change Tracking




Note from the Project 2010-07 SDT The redline changes included in this document are the work of the Project 2010-07 SDT and are provided as a companion to the teamrsquos White Paper the aim is to provide an example to convey the direction of our proposal This is not intended to be a comprehensive rewrite of the standard Any formal standard revision would require coordination with the work of the drafting team currently revising FAC-003-2 under Project 2007-07

Standard Development Timeline 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 15ndashFebruary 14 2007)

3 SAR posted for comment (April 10ndashMay 9 2007)

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

5 First draft of proposed standard posted (October 27 2008-November 25 2008))

6 Second draft of revised standard posted (September 10 20-October 24 2009)

7 Third draft of revised standard posted (March 1 2010-March 31 2010)

8 Forth draft of revised standard posted (June 17 2010-July 17 2010)

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

Recirculation ballot of standards January 2011

Receive BOT approval February 2011



Effective Dates

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



Vers ion His tory Version Date Action Change Tracking

1 TBA 1 Added ldquoStandard Development Roadmaprdquo

2 Changed ldquo60rdquo to ldquoSixtyrdquo in section A 52

3 Added ldquoProposed Effective Date April 7 2006rdquo to footer

4 Added ldquoDraft 3 November 17 2005rdquo to footer

012006

1 April 4 2007 Regulatory Approval mdash Effective Date New 2



Defin itions of Terms Us ed in Standard 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 Ownerrsquos 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 Ownerrsquos 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



In troduc tion 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

41 Functional Entities Transmission Owners

Generator Owners

42 Facilities Defined below (referred to as ldquoapplicable linesrdquo) including but not limited to those that cross lands owned by federal1

421 Overhead transmission lines operated at 200kV or higher

state provincial public private or tribal entities

422 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

423 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

424 This standard applies to overhead transmission lines identified above (421 through 423) 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 ldquoAccess approvals by Federal agenciesrdquo

Rationale -The areas excluded in 424 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 doesnrsquot makes the standard stronger as it relates to clarity

Formatted Normal Indent Left 0 SpaceAfter 0 pt Tab stops Not at 113



43 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 (ldquoStandardrdquo) 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 mdash defines a particular reliability objective or outcome to be achieved

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

c) Competency-based mdash 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

bull Performance-based Requirements 1 and 2

bull Competency-based Requirement 3

bull 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 ldquopublic landsrdquo 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 Standardrsquos emphasis is on vegetation grow-ins



Requirements and Meas ures R1 Each Transmission Owner and Generator

Owner shall manage 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 ndash High] [Time Horizon ndash Real-time]

M1 Each Transmission Owner and Generator 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 or Generator 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 the Generator Owner or an applicable regulatory body ice storms and floods and 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 Ownerrsquos right to exercise its full legal rights on the ROW






Owner shall manage 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 ndash Medium] [Time Horizon ndash Real-time]

M2 Each Transmission Owner and Generator 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







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 include(s) the following 31 Accounts for the movement of

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

32 Accounts for the inter-relationships between vegetation growth rates vegetation control methods and inspection frequency

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

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


Owner without any intentional time delay shall notify the control center holding switching authority for the associated applicable transmission line when the Transmission Owner or Generator Owner has confirmed the existence of a vegetation condition that is likely to cause a Fault at any moment

[VRF ndash Medium] [Time Horizon ndash Real-time] M4 Each Transmission Owner and Generator 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 Ownerrsquos 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 or Generator 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 or Generator Owner shall take corrective action to ensure continued vegetation management to prevent encroachments [VRF ndash Medium] [Time Horizon ndash Operations Planning] M5 Each Transmission Owner and

Generator 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)


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 ROW3

[VRF ndash Medium] [Time Horizon ndash Operations Planning] M6 Each Transmission Owner and

Generator Owner has evidence that it conducted Vegetation Inspections of the transmission line ROW for all applicable

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



transmission lines at least once per calendar year but with no more than 18 months between inspections on the same ROW Examples of acceptable forms of evidence may include completed and dated work orders dated invoices or dated inspection records (R6)


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

bull Change in expected growth rate environmental factors bull Circumstances that are beyond the control of a Transmission Owner or Generator

Owner4

bull Rescheduling work between growing seasons

bull Crew or contractor availability Mutual assistance agreements bull Identified unanticipated high priority work bull Weather conditionsAccessibility bull Permitting delays bull Land ownership changesChange in land use by the landowner bull Emerging technologies

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

M7 Each Transmission Owner and Generator 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 or Generator 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 GO 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



Compliance


bull Regional Entity


bull Compliance Audits bull Self-Certifications bull Spot Checking bull Compliance Violation Investigations bull Self-Reporting bull Complaints bull 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


Additional Compliance Information Periodic Data Submittal The Transmission Owner will submit a quarterly report to its Regional Entity or the Regional Entityrsquos 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 mdash 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 andor outside of the ROW



o Category 1B mdash 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 andor outside of the ROW

o Category 2A mdash 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 mdash 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 mdash Fall-ins Sustained Outages caused by vegetation falling into applicable transmission lines from outside the ROW

o Category 4A mdash 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 mdash 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 Viola tion Ris k Factors and Viola tion Severity Leve ls

Table 1

R Time Horizon

VRF Violation Severity Level

Lower Moderate High Severe

R1 Real-time High










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 Ownerrsquos applicable lines

movement of transmission line conductors under their Rating and all Rated Electrical Operating Conditions for the Transmission Ownerrsquos applicable lines

encroachment of vegetation into the MVCD for the Transmission Ownerrsquos applicable lines


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 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)



Variances None In te rpre ta tions 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 (ldquoMVCDrdquo) of transmission lines R1 is applicable to lines ldquoidentified 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 Outagerdquo 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 Ownerrsquos vegetation programrsquos ability to meet the goal of ldquopreventing a Sustained Outage that could lead to Cascadingrdquo Thus violation severity increases with a Transmission Ownerrsquos 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 conductorrsquos 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 velocitydirection 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 Ownerrsquos 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 Ownerrsquos 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

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

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

bull Documenting and tracking the specific action taken for each location bull 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 andor 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

bull 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 Ownerrsquos 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 2000 miles of 230 kV transmission lines this Transmission Owner will be responsible for inspecting all 2000 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 1002000 = 005 or 5 The ldquoLow VSLrdquo 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 ldquospan-by-spanrdquo or even a ldquoline-by-linerdquo 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 Ownerrsquos 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 Ownerrsquos 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 mdashmdash TTAABBLLEE 22 mdashmdash MMiinniimmuumm VVeeggeettaattiioonn CClleeaarraannccee DDiissttaanncceess ((MMVVCCDD))5

For Alternating Current Voltages

5

( AC ) Nominal System Voltage (kV)

( AC ) Maximum System Voltage (kV)

MVCD feet

(meters)

sea level

MVCD


(9144m)

MVCD


(12192m)

MVCD


(1524m)

MVCD


(18288m)

MVCD


(21336m)

MVCD


(24384m)

MVCD


(27432m)

MVCD

feet (meters) 10000ft (3048m)

MVCD


(33528m)

765 800 806ft (246m)

889ft (271m)

917ft (280m)

945ft (288m)

973ft (297m)

1001ft (305m)

1029ft (314m)

1057ft (322m)

1085ft (331m)

1113ft (339m)

500 550 506ft (154m)

566ft (173m)

586ft (179m)

607ft (185m)

628ft (191m)

649ft (198m)

67ft (204m)

692ft (211m)

713ft (217m)

735ft (224m)

345 362 312ft (095m)

353ft (108m)

367ft (112m)

382ft (116m)

397ft (121m)

412ft (126m)

427ft (130m)

443ft (135m)

458ft (140m)

474ft (144m)

230 242 297ft (091m)

336ft (102m)

349ft (106m)

363ft (111m)

378ft (115m)

392ft (119m)

407ft (124m)

422ft (129m)

437ft (133m)

453ft (138m)

161 169 2ft (061m)

228ft (069m)

238ft (073m)

248ft (076m)

258ft (079m)

269ft (082m)

28ft (085m)

291ft (089m)

303ft (092m)

314ft (096m)

138 145 17ft (052m)

194ft (059m)

203ft (062m)

212ft (065m)

221ft (067m)

23ft (070m)

24ft (073m)

249ft (076m)

259ft (079m)

27ft (082m)

115 121 141ft (043m)

161ft (049m)

168ft (051m)

175ft (053m)

183ft (056m)

191ft (058m)

199ft (061m)

207ft (063m)

216ft (066m)

225ft (069m)

88 100 115ft (035m)

132ft (040m)

138ft (042m)

144ft (044m)

15ft (046m)

157ft (048m)

164ft (050m)

171ft (052m)

178ft (054m)

186ft (057m)

69 72 082ft (025m)

094ft (029m)

099ft (030m)

103ft (031m)

108ft (033m)

113ft (034m)

118ft (036m)

123ft (037m)

128ft (039m)

134ft (041m)

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)) mdashmdash MMiinniimmuumm VVeeggeettaattiioonn CClleeaarraannccee DDiissttaanncceess ((MMVVCCDD)) For Direct Current Voltages

( DC ) Nominal Pole

to Ground Voltage

(kV)

MVCD feet

(meters)

sea level

MVCD feet

(meters) 3000ft

(9144m) Alt

MVCD feet

(meters) 4000ft

(12192m) Alt

MVCD feet

(meters) 5000ft

(1524m) Alt

MVCD feet

(meters) 6000ft

(18288m) Alt

MVCD feet

(meters) 7000ft

(21336m) Alt

MVCD feet

(meters) (8000ft

(24384m) Alt

MVCD feet

(meters) 9000ft

(27432m) Alt

MVCD feet

(meters) 10000ft (3048m)

Alt

MVCD feet

(meters) 11000ft

(33528m) Alt

plusmn750 1392ft (424m)

1507ft (459m)

1545ft (471m)

1582ft (482m)

162ft (494m)

1655ft (504m)

169ft (515m)

1727ft (526m)

1762ft (537m)

1797ft (548m)

plusmn600 1007ft (307m)

1104ft (336m)

1135ft (346m)

1166ft (355m)

1198ft (365m)

123ft (375m)

1262ft (385m)

1292ft (394m)

1324ft (404m)

(1354ft 413m)

plusmn500 789ft (240m)

871ft (265m)

899ft (274m)

925ft (282m)

955ft (291m)

982ft (299m)

101ft (308m)

1038ft (316m)

1065ft (325m)

1092ft (333m)

plusmn400 478ft (146m)

535ft (163m)

555ft (169m)

575ft (175m)

595ft (181m)

615ft (187m)

636ft (194m)

657ft (200m)

677ft (206m)

698ft (213m)

plusmn250 343ft (105m)

402ft (123m)

402ft (123m)

418ft (127m)

434ft (132m)

45ft (137m)

466ft (142m)

483ft (147m)

5ft (152m)

517ft (158m)

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



bull avoid the problem associated with referring to tables in another standard (IEEE-516-2003) bull transmission lines operate in non-laboratory environments (wet conditions) bull 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 35 for voltages up to 362 kV phase to phase 30 for 500 - 550 kV phase to phase and 25 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 (ie 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 20 per unit This value is a conservative estimate of the transient over-voltage that is created at the point of application (eg a substation) by switching a capacitor bank without pre-insertion devices (eg closing resistors) At voltage levels where capacitor banks are not very common (eg 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 15 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 20 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 14 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 D5 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 ldquowetrdquo formulas are not vastly different when the same transient overvoltage factors are used the ldquowetrdquo 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



765 800 14 889 865 500 550 14 565 492 345 362 14 352 313 230 242 20 335 28 115 121 20 16 14

Table 5

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


765 800 20 1436 1395 500 550 24 110 1007 345 362 30 855 747 230 242 30 528 42 115 121 30 246 21





765 800 25 2025 204 500 550 30 1502 147 345 362 35 1042 944 230 242 35 632 514 115 121 35 290 245

PPrroojjeecctt 22001100--0077 GGeenneerraattoorr RReeqquuiirreemmeennttss aatt tthhee

TTrraannssmmiissssiioonn IInntteerrffaaccee

WWhhiittee PPaappeerr PPrrooppoossaall ffoorr IInnffoorrmmaall CCoommmmeenntt

March 2011


TTaabbllee ooff CCoonntteennttss Introduction 2

Objective 2

Proposed Next Steps and Review of Reliability Standards 4

Summary and Discussion of Other Solutions 7


Project 2010-07 Generator Requirements at the Transmission Interface White Paper Proposal for Informal Comment Introduction The Bulk Electric System1 consists of many parts including power plants and transmission facilities While most transmission facilities operate as part of the overall integrated grid a number of transmission facilities operate more like an extension cord to interconnect power plants and loads to the bulk power system2

These transmission facilities that connect power plants to the integrated grid are commonly known as generator interconnection facilities

Power plants and their respective pieces and parts come in all sizes and configurations Some plants consist of just a single generating unit other plants consist of multiple generating units and still others consist of multiple generating units spread over several thousand acres While not all power plants are considered part of the Bulk Electric System ultimately all the plants are interconnected to the bulk power system via their generator interconnection facilities Of concern is how to classify all such generating facilities including their generator interconnection facilities to determine what level of reliability is needed for such facilities Objective The purpose of Project 2010-07mdashGenerator Requirements at the Transmission Interface is to ensure that all generator-owned Facilities3

that are considered part of the Bulk Electric System are identified and that the level of reliability needed to operate such Facilities is appropriately covered under NERCrsquos Reliability Standards This will be accomplished by proposing a set of changes to existing standard requirements introducing new requirements and if necessary modifying definitions of some NERC-defined terms The collective efforts will add clarity to Generator Owners and Generator Operators regarding their reliability standard obligations at the interface with the integrated bulk power system

Since the formation of the Project 2010-07 Standard Drafting Team (SDT) in December 2010 the SDT has focused on reworking the Generator Requirements at the Transmission Interface Ad Hoc Grouprsquos4

1The current definition of ldquoBulk Electric Systemrdquo in the

(GOTO Ad Hoc Group) original proposed plan for addressing generator

NERCrsquos Glossary of Terms reads ldquoAs defined by the Regional Reliability Organization the electrical generation resources transmission lines interconnections with neighboring systems and associated equipment generally operated at voltages of 100 kV or higher Radial transmission facilities serving only load with one transmission source are generally not included in this definitionrdquo This definition is undergoing significant revision under Project 2010-17mdashDefinition of Bulk Electric System 2 This paper uses the term ldquobulk power systemrdquo as it is defined in Section 215 of the Federal Power Act ldquo(A) facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof) and (B) electric energy from generation facilities needed to maintain transmission system reliability The term does not include facilities used in the local distribution of electric energyrdquo 3 ldquoFacilityrdquo is defined in NERCrsquos Glossary of Terms as ldquoA set of electrical equipment that operates as a single Bulk Electric System Element (eg a line a generator a shunt compensator transformer etc)rdquo 4 NERC formed the Generator Requirements at the Transmission Interface Ad Hoc Group in 2009 to analyze and make recommendations for establishing general criteria for determining whether Generator Owners and Generator Operators should be registered for Transmission Owner and Transmission Operator requirements in NERCrsquos Reliability Standards


requirements at the transmission interface Based on feedback from the industry along with input from NERC and FERC staffs the GOTO Ad Hoc Group made a series of recommendations that included changes to various reliability standards the modification of existing definitions and the creation of some new definitions However based on more recent feedback from industry and regulators and after taking into account other standards projects under development the SDT decided that the plan of proposing new definitions modifying other definitions and making changes to dozens of standards was no longer necessary The SDT believes it is appropriate to classify various generating Facilities and Elements (including generator interconnection facilities) as part of the Bulk Electric System The SDT also believes that qualifying generator interconnection facilities should be classified as transmission That does not mean however that a Generator Owner or Generator Operator should be required to automatically register as a Transmission Owner or Transmission Operator simply because it owns andor operates transmission Elements or Facilities While qualifying Generator Owners and Generator Operators can be classified as owning and operating electric transmission Elements and Facilities these are most often not part of the integrated bulk power system and as such should not be subject to the same level of standards applicable to Transmission Owners and Transmission Operators who own and operate transmission Facilities and Elements that are part of the integrated bulk power system Requiring any classification that subjects Generator Owners and Generator Operators to all the standards applicable to Transmission Owners and Transmission Operators would do little if anything to improve the reliability of the Bulk Electric System When the transmission Elements and Facilities owned and operated by Generator Owners and Generator Operators are non-networknon-integrated transmission applying all standards applicable to Transmission Owners and Transmission Operators would have little effect on the overall reliability of the Bulk Electric System when compared to the operation of the equipment that actually produces electricity ndash the generation equipment itself To maintain an adequate level of reliability in the Bulk Electric System a clear delineation of responsibilities and authority at the interface between Generator OwnersOperators and Transmission OwnersOperators is needed This can be accomplished by properly applying selected standards or specific standard requirements to Generator Owners and Generator Operators The SDT is recommending a plan to modify the Purpose the Functional Entity section requirements and measures of a selected group of standards to make them applicable to Generator Owners and Generator Operators and to add clarity to such standards regarding generator interconnection facilities Note that at this stage in its work the SDT has made no final decisions on its proposed plan rather it is seeking informal feedback from the industry regarding its assumptions and recommendations Throughout the informal comment stage the SDT plans to rely heavily on this informal input and feedback to lessen the need to expend limited industry resources on developing specific and exacting standards changes At this informal stage the SDT has not developed definitional changes VSLs VRFs Implementation Plans etc for its proposed changes those will be developed as needed once the project progresses further and proposed changes are finalized


Proposed Next Steps and Review of Reliability Standards The Project 2010-07 Standard Drafting Team (SDT) proposes the following recommendations to clearly identify the appropriate generation Facilities and the standards requirements that should apply to such generation Facilities to ensure that the reliability of the Bulk Electric System is maintained

1 Add ldquoGenerator Ownerrdquo to the Applicability section of FAC-001-0 and add a requirement and a measure to address the responsibilities specific to the Generator Owner FAC-001-0mdashFacility Connection Requirements currently applies to Transmission Owners and addresses the need for Transmission Owners to establish facility connection and performance requirements While the standard requires Transmission Owners to address connection requirements for ldquogeneration facilities transmission facilities and end-user facilitiesrdquo it does not address the requirements for a Generator Owner that has received a request for interconnection The lack of such requirements for a Generator Ownerrsquos Facility could result in gaps Therefore the SDT proposes that ldquoGenerator Ownerrdquo be added to the Applicability section of FAC-001-0 It further proposes the addition of Requirement 4 and a corresponding measure


M4 The Generator Owner that receives an interconnection request for its facility

shall make available (to its Compliance Monitor) for inspection evidence that it met the requirements stated in Reliability Standard FAC-001-0 R4

These proposed standard changes are redlined in Attachment 1 Note that FAC-001-0 has been assigned for modification under Project 2010-02 but as of March 4 2011 no activity has yet taken place on that project

2 Add ldquoGenerator Ownerrdquo to the Applicability section of FAC-003-2 and modify the

requirements and measures to include Generator Owner

The proposed FAC-003-2 currently applies to Transmission Owners and addresses the need 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 A Transmission Vegetation Management Plan is used to ensure the reliable operation of electric transmission systems and prevent vegetation-related outages Because generator-owned Facilities may include electric transmission FAC-003-2 should be applicable to


Generator Owners Requiring Generator Owners to adhere to the requirements in this standard will ensure that Facilities like the generator interconnecting line lead are inspected as defined in the Transmission Vegetation Management Plan and that all vegetation that breaches specified clearances is properly trimmed This change in applicability will also ensure the proper reporting of vegetation-related outages to the appropriate Regional Reliability Organizations

The SDT proposes that ldquoGenerator Ownerrdquo is added to all requirements and measures that mention the Transmission Owner These proposed changes are outlined in Attachment 2 The SDT recognizes that if these standard changes are made changes to the accompanying FAC-003-2 definition modifications may also be needed As noted above such changes will be considered after informal comments are received

3 Follow the Project 2010-17mdashDefinition of Bulk Electric System and ensure that the

responsibility for generator interconnecting line leads is appropriately and clearly assigned to Generator Owners and Operators

The Project 2010-07 SDT recognizes that it cannot control the work of the SDT working on the definition of Bulk Electric System Still the Project 2010-07 SDT is hopeful that changes made to this definition will be instrumental in covering the reliability gap with respect to generator requirements at the transmission interface At this stage in the definitionrsquos development Project 2010-17rsquos concept paper has a section on Proposed BES Criteria and it includes the following

3 Generation plants (including GSU transformers and the associated generator interconnecting line lead(s)) with aggregate capacity greater than 75 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above

The Project 2010-07 SDT recognizes that this concept paper is a working draft and is in no way enforceable at this time still the Project 2010-07 SDT is hopeful that the BES team is moving in a direction that will be complementary to its own work

The proposed changes listed above mark a significant decrease in changes originally proposed by the GOTO Ad Hoc Group in its Final Report In particular clarifications to the definition of Bulk Electric System eliminate the need for the GOTO Ad Hoc Grouprsquos suggestions to include a reference to the proposed new term ldquoGenerator Interconnection Facilityrdquo in the following standards referenced in the GOTO Ad Hoc Group Final Report

bull BAL-005-01b bull CIP-002-1 bull EOP-001-0 bull EOP-004-1 bull FAC-008-1 bull FAC-009-1


bull IRO-005-2 bull MOD-010-0 bull MOD-012-0 bull PRC-004-1 bull PRC-005-1 bull TOP-002-2 bull TOP-003-0 bull VAR-001-1 bull VAR-002-1

All of the standards listed above already apply to the Generator Owner or Generator Operator5

so as long as generator-owned Facilities like generator interconnection facilities are appropriately assigned to the responsibility of those entities with changes to the definition of Bulk Electric System there should be no need to highlight the inclusion of ldquoGenerator Interconnection Facilityrdquo with language changes in those standards

Other proposed changes are also unnecessary In EOP-003-1 the GOTO Ad Hoc Group had originally proposed that Generator Operators be added to the requirement that requires Transmission Operators and Balancing Authorities to coordinate automatic load-shedding throughout their areas The SDT determined that this addition was unnecessary because PRC-001 already includes the requirement that Transmission Operators coordinate their UFLS programs with underfrequency isolation of generating units which infers that Generator Operators need to provide their underfrequency settings to their respective Transmission Operator Further Generator Operators should not be involved in the high-level coordination that this standard requires In EOP-008-0 the proposed reference to the Generator Interconnection Operational Interface can be eliminated because the proposed term was meant to consist of Elements and Facilities rated at 100 kV and above which the team has acknowledged are transmission In the cases of PER-001-0 and PER-002-0 the SDT believes that additional requirements for training of Generator Owner and Generator Operator personnel should be addressed in a future project In FERC Order 693 a directive applied ldquoto generator operator personnel at a centrally-located dispatch center who receive direction and then develop specific dispatch instructions for plant operators under their controlrdquo FERC directed that those Generator Operator personnel receive formal training of the nature provided to system operators under PER-005-1 FERC Order 742 confirms that the Commission has ldquonot modified the scope of applicability of the Order 693 directive regarding generator operator trainingrdquo

The SDT has also considered proposing further modifications to PRC-001-2 to ensure coordination of protection system information among Generator Operators and Transmission Operators and to standards TOP-001-2 and TOP-003-2 (all of which are currently under development) to ensure that coordination of information among Generator Operators and Transmission Operators The SDT has consulted with the members of the Project 2007-03mdash

5 Many have also changed significantly since the GOTO Ad Hoc Grouprsquos review


Real-time Operations SDT and believes that the necessary level of coordination (including for Special Protection Systems) is covered by the requirements in the proposed new TOP-003-2 In TOP-004-2 the GOTO Ad Hoc Grouprsquos addition of R7 (requiring the Generator Operator to operate its generator interconnection facility within its applicable ratings) is not needed because existing TOP and IRO standards require entities to operate within or to mitigate SOLs and IROLs at the direction of the TOP and RC The proposed addition of R5 to TOP-008-1 is also unnecessary because it will be covered in the data specifications of TOP-003-2 R1 (TOP-008 is being retired) Summary and Discussion of Other Solutions Again the purpose of this project is to clearly identify the appropriate generation Facilities and the standards requirements that should apply to such generation Facilities to ensure that the reliability of the Bulk Electric System is maintained The SDT recognizes that its work alone may not eliminate all reliability gaps with respect to generator-owned Facilities like generator interconnection facilities As noted above Project 2010-17mdashDefinition of Bulk Electric System may have an enormous impact on the work of this SDT We are confident that these changes we have proposed to a small number of standards in coordination with changes to the Bulk Electric System definition can achieve the necessary reliability but we also acknowledge that many entities have taken advantage of solutions outside the standards process that have achieved the same effect On April 20 2010 NERC Compliance published a Public Bulletin to provide guidance for situations like this in which entities delegate reliability tasks to a third-party entity In this bulletin NERC Compliance emphasizes that while a registered entity may not delegate its responsibility for ensuring that a task is completed it may delegate the performance of a task to another entity As is explained in the bulletin compliance responsibility for applicable NERC Reliability Standard requirements and accountability for violations thereof may be achieved through several means including the following

1 By Individual an entity is registered on the NERC Compliance Registry and such registered entity assumes full compliance responsibility and accountability or

2 By Written Contract parties enter into written agreement whereby

a A registered entity delegates the performance of some or all functional activities to a third party that is not a registered entity and the registered entity retains full compliance responsibility and violation accountability or

b A registered entity delegates the performance of some or all of the functional activities to a third party and the third party accepts full compliance responsibility for the specific functions it performs and violation accountability In this case there may be individual concurrent or joint registration of the entities depending on the nature of the contractual relationship and in any event only the registered entity would be held responsible or accountable by a Regional Entity or NERC or


3 By Joint Registration Organization (JRO) each party is registered and is required to clearly identify and allocate compliance responsibility and violation accountability for their respective functions under applicable NERC Reliability Standard requirements

Because the standards efforts outlined here will not take effect for a year or more Generator Owners and Generator Operators that are concerned about their registration status should explore options like those explained above and in further detail in NERC Compliance Bulletin 2010-004 The Project 2010-07 SDT will continue with the efforts outlined above but will modify its proposal and ultimate actions based on feedback from the industry


Project 2010-07 Generator Requirements at the Transmission Interface Informal Comment Period Open March 4 ndash April 4 2011 Now available at httpwwwnerccomfilezstandardsProject2010-07_GOTO_Projecthtml Informal Comment Period Open through 8 pm Eastern on Monday April 4 2011 The Project 2010-07 Generator Requirements at the Transmission Interface drafting team has posted for a 30-day informal comment period a White Paper on proposed concepts to support the modifications of various standards to clarify the reliability standard responsibilities of Generator Owners and Generator Operators at the interface to the interconnected grid The White Paper along with proposed redlined changes to standards that would be affected by the proposal have been posted on the project Web page at httpwwwnerccomfilezstandardsProject2010-07_GOTO_Projecthtml Instructions The drafting team welcomes any constructive feedback for improving its proposal to ensure that the responsibilities of Generator Owners and Generator Operators at the interface to the interconnected grid are covered under NERCrsquos Reliability Standards Consider using the following questions to focus your comments

bull How can the proposal outlined in the White Paper be improved Is the drafting team heading in the right direction

bull The drafting team has chosen to use informal means of receiving industry feedback (webinars presentations before industry stakeholder groups etc) prior to expending valuable industry resources to develop specific proposals for reliability standard requirements measures VSLs etc Do you have any further suggestions for seeking industry input before the project moves into a more formal development phase

bull The Ad Hoc group originally proposed the new terms ldquoGenerator Interconnection Facilityrdquo and ldquoGenerator Interconnection Operational Interfacerdquo as part of this project The Project 2010-07 drafting team believes that changes to the definition of Bulk Electric System under Project 2010-17 and modifications to a select group of standards can accomplish the same goal without the need for new definitions Do you support this approach If not please explain

Please submit comments by e-mail to Mallory Huggins at malloryhugginsnercnet Next Steps The drafting team will consider the input received on the concept White Paper as it continues its work

Project Background Significant industry concern exists regarding the application of Transmission Owner and Transmission Operator requirements and more specifically 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 NERC formed the Generator Requirements at the Transmission Interface Ad Hoc Group in 2009 to analyze and make recommendations for establishing general criteria for determining whether Generator Owners and Generator Operators should be registered for Transmission Owner and Transmission Operator requirements in NERCrsquos Reliability Standards The Ad Hoc Group developed a report evaluating the issues and proposing a number of changes to add clarity on the requirements for generator interconnection facilities Using feedback from the industry NERC and FERC the Project 2010-07 drafting team significantly revised the Ad Hoc Grouprsquos original proposal and offers a refined proposal here Standards Process The Standard Processes Manual contains all the procedures governing the standards development process The success of the NERC standards development process depends on stakeholder participation We extend our thanks to all those who participate






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 (April 2009)

2 SAR posted for comment (April 22 ndash May 21 2009)

3 SC authorized moving the SAR forward to standard development (September 2009)

4 Concepts Paper posted for comment (March 17 ndash April 16 2010)

5 Initial Informal Comment Period (September 2010)

Proposed Action Plan and Description of Current Draft This is the first posting of the proposed standard in accordance with Results-Based Criteria The drafting team requests posting for a 30-day formal comment period Future Development Plan

Anticipated Actions Anticipated Date Initial Comment PeriodDrafting team considers comments makes conforming changes and proceed to second comment

SeptemberOctober 2010 ndash February 2011

Drafting team considers comments makes conforming changes and proceed to second comment Second Comment Period

October ndash December 2010March ndash May 2011

Third Comment PeriodInitial Ballot period December 2010- JanuaryJune- July 2011

Successive CommentRecirculation Ballot period February ndash MarchJuly-August 2011

Receive BOT approval AprilSeptember 2011



EEffffeeccttiivvee DDaatteess 1 USA The standard shall become effective on the Ffirst calendar day of the ffiirrssttthird calendar quarter oonnee yyeeaarr after the date of the order providing applicable regulatory authority approval for all requirements 2 Canada and Mexico FFiirrsstt ccaalleennddaarr ddaayy ooffConcurrent with the ffiirrsstt ccaalleennddaarr qquuaarrtteerr oonnee yyeeaarr ffoolllloowwiinngg BBooaarrdd ooff TTrruusstteeeess aaddooppttiioonn uunnlleessss ggoovveerrnnmmeennttaall aauutthhoorriittyy wwiitthhhhoollddss aapppprroovvaallEffective Date for the USA In those jurisdictions where no regulatory approval is required the standard shall become effective on the first calendar day of the third calendar quarter after Board of Trustees adoption VVeerrssiioonn HHiissttoorryy Version Date Action Change Tracking

2 Merged CIP-001-1 Sabotage Reporting and EOP-004-1 Disturbance Reporting into EOP-004-2 Impact Event Reporting Retire CIP-001-1a Sabotage Reporting and Retired EOP-004-1 R1 R32 R33 R34 R4 R5 and associated measures evidence retention and VSLs Disturbance Reporting Added new requirements for ERO ndash R1 R7 R8

Revision to entire standard (Project 2009-01)





Formatted Normal



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 None Impact Event Any event which has either impacted or has the potential to impact the reliability of the Bulk Electric System Such events may be caused by equipment failure or mis-operation environmental conditions or human action



When this standard has received ballot approval the text boxes will be moved to the Guideline and Technical Basis Section

Introduction

1 Title Impact Event and Disturbance Assessment Analysis and Reporting 2 Number EOP-004-2 3 Purpose Responsible Entities shall report impact events and their known causes to

support situationalTo improve industry awareness and the reliability of the Bulk Electric System (BES)by requiring the reporting of Impact Events and their causes if known by the Responsible Entities

4 Applicability 41 Functional Entities Within the context of EOP-004-2 the term ldquoResponsible

Entityrdquo shall mean 411 Reliability Coordinator 412 Balancing Authority 413 Interchange Authority 414 Transmission Service Provider 413415 Transmission Owner 414416 Transmission Operator 415417 Generator Owner 416418 Generator Operator 417419 Distribution Provider 418 Electric Reliability Organization 4110 Load Serving Entity

5 Background NERC established a SAR Team in 2009 to investigate revisions to the CIP-001 and EOP-004 Reliability Standards

1 CIP-001 may be merged with EOP-004 to eliminate redundancies 2 Acts of sabotage have to be reported to the DOE as part of EOP-004 3 Specific references to the DOE form need to be eliminated 4 EOP-004 has some lsquofill-in-the-blankrsquo components to eliminate

The development may include other improvements to the standards deemed appropriate by the drafting team with the consensus of stakeholders consistent with establishing high quality



enforceable and technically sufficient bulk power system reliability standards (see tables for each standard at the end of this SAR for more detailed information) The SAR for Project 2009-01 Disturbance and Sabotage Reporting was moved forward for standard drafting by the NERC SC in August of 2009 The Disturbance and Sabotage Reporting Standard Drafting Team (DSR SDT) was formed in late 2009 A ldquoconcepts paperrdquo was designed to solicit stakeholder input regarding the proposed reporting concepts that the DSR SDT has developed The concept paper sought comments from stakeholders on the ldquoroad maprdquo that will be used by the SDR SDT in updating or revising CIP-001 and EOP-004 The concept paper provided stakeholders the background information and thought process of the SDR SDT The DSR SDT has reviewed the existing standards the SAR issues from the NERC database and FERC Order 693 Directives in order to determine a prudent course of action with respect to these standards The DSR SDT has proposed the following concept for impact eventused a working definition for ldquoImpact Eventsrdquo to develop Attachment 1 as follows

ldquoAn impact eventImpact Event is any event that has either impacted or has the potential to impact the reliability of the Bulk Electric System Such events may be caused by equipment failure or mis-operation environmental conditions or human actionrdquo

The DSR SDT has proposed this definition for inclusion in the NERC Glossary for ldquoImpact Eventrdquo The types of Impact Events that are required to be reported are contained within Attachment 1 Only these events are required to be reported under this Standard The DSR SDT considered the FERC directive to ldquofurther define sabotagerdquo and decided to eliminate the term sabotage from the standard The team felt that it was almost impossible to determine if an act or event was that of sabotage or merely vandalism without the intervention of law enforcement after the fact This will result in further ambiguity with respect to reporting events The term ldquosabotagerdquo is no longer included in the standard and therefore it is inappropriate to attempt to define it The Impact Events listed in Attachment 1 provide guidance for reporting both actual events as well as events which may have an impact on the Bulk Electric System The DSR SDT believes that this is an equally effective and efficient means of addressing the FERC Directive Attachment 1 Part A is to be used for those actions that have impacted the electric system and in particular the section ldquoDamage or destruction to equipmentrdquo clearly defines that all equipment that intentional or non intentional human error be reported Attachment 1 Part B covers the similar items but the action has not fully occurred but may cause a risk to the electric system and is required to be reported To support this concept the DSR SDT has provided specific event for reporting including types of impact eventsImpact Events and timing thresholds pertaining to the different types of impact eventsImpact Events and whorsquos responsibility for reporting under the different impact eventsImpact Events This information is outlined in Attachment 1 to the proposed standard



The DSR SDT wishes to make clear that the proposed changes do not include any real-time operating notifications for the types of events covered by CIP-001 EOP-004 This is achieved through the RCIS and is covered in other standards (eg TOP) The proposed standard deals exclusively with after-the-fact reporting The DSR SDT is proposing to consolidate disturbance and impact eventImpact Event reporting under a single standard These two components and other key concepts are discussed in the following sections Summary of Concepts

bull A single form to report disturbances and impact eventsImpact Events that threaten the reliability of the bulk electric system

bull Other opportunities for efficiency such as development of an electronic form and possible inclusion of regional reporting requirements

bull Clear criteria for reporting bull Consistent reporting timelines bull Clarity around of who will

receive the information and how it will be used

Law Enforcement Reporting The reliability objective of EOP-004-2 is to prevent outages which could lead to Cascading by effectively reporting Impact Events Certain outages such as those due to vandalism and terrorism are not preventable Entities rely upon law enforcement agencies to respond and investigate those Impact Events which have the potential of wider area affect upon the industry which enables and supports reliability principles such as protection of bulk power systems from malicious physical or cyber attack The Standard is intended to reduce the risk of Cascading involving Impact Events The importance of BES awareness of the threat around them is essential to the effective operation and planning to mitigate the potential risk to the BES Stakeholders in the Reporting Process

bull Industry

Rationale for R1 The goal of the DSR SDT is to have a generic reporting form and a system for all functional entities (US Canada Mexico) to submit impact event reports to NERC and other entities Ultimately it may make sense to develop an electronic version of the form to expedite completion sharing and storage Ideally entities would complete a single electronic form on-line which could then be electronically forwarded or distributed to jurisdictional agencies and functional entities as appropriate using check boxes or other coding within the electronic form Specific reporting forms that exist today (ie - OE-417 etc) could be included as part of the electronic form to accommodate US entities with a requirement to submit the form or may be removed (but still be mandatory for US entities under Public Law 93-275) to streamline the proposed consolidated reliability standard for all North American entities (US Canada Mexico) Jurisdictional agencies may include DHS FBI NERC RE FERC Provincial Regulators and DOE Functional entities may include the RC TOP and BA for situational awareness Applicability of the standard will be determined based on the specific requirements The DSR SDT recognizes that some regions require reporting of additional information beyond what is in EOP-004 The DSR SDT is planning to update the listing of reportable events from discussions with jurisdictional agencies NERC Regional Entities and stakeholder input There is a possibility that regional differences may still exist Responsible entities will ultimately be responsible for ensuring that OE-417 reports are received at the DOE



bull NERC (ERO) bull FERC bull DOE bull DHS ndash Federal bull Homeland Security- State bull State Regulators bull Local Law Enforcement bull State Law Enforcement bull FBI

The above stakeholders have an interest in the timely notification communication and response to an incident at an industry facility The stakeholders have various levels of accountability and have a vested interest in the protection and response to ensure the reliability of the BES Present expectations of the industry under CIP-001 It has been the understanding by industry participants that an occurrence of sabotage has to be reported to the FBI The FBI has the jurisdictional requirements to investigate acts of sabotage and terrorism The present CIP-001-1 standard requires a liaison relationship on behalf of the industry and FBI Annual requirements under the standard of the industry have not been clear and have lead to misunderstandings and confusion in the industry as to how to demonstrate the liaison is in place and effective FBI offices have been asked to confirm on FBI letterhead the existence of a working relationship to report acts of sabotage to include references to years the liaison has been in existence and confirming telephone numbers for the FBI Coordination of Local and State Law Enforcement Agencies with the FBI The Joint Terrorism Task Force (JTTF) came into being with the first task force being established in 1980 JTTFs are small cells of highly trained locally based passionately committed investigators analysts linguists SWAT experts and other specialists from dozens of US law enforcement and intelligence agencies The JTTF is a multi-agency effort led by the Justice Department and FBI designed to combine the resources of federal state and local law enforcement Coordination and communications largely through the interagency National Joint Terrorism Task Force working out of FBI Headquarters which makes sure that information and intelligence flows freely among the local JTTFs This information flow can be most beneficial to the industry in analytical intelligence incident response and investigation Historically the most immediate response to an industry incident has been local and state law enforcement agencies to suspected vandalism and criminal damages at industry facilities Relying upon the JTTF coordination between local state and FBI law enforcement would be beneficial to effective communications and the appropriate level of investigative response Coordination of Local and Provincial Law Enforcement Agencies with the RCMP A similar law enforecment coordination hierarchy exists in Canada Local and Provincial law enforcement coordinate to investigate suspected acts of vandalism and sabotage The Provincial



law enforcement agency has a reporting relationship with the Royla Canadian Mounted Police (RCMP) A Reporting Process Solution ndash EOP-004 A proposal discussed with FBI FERC Staff NERC Standards Project Coordinator and SDT Chair is reflected in the flowchart below (Reporting Hierarchy for Impact Event EOP-004-2) Essentially reporting an Impact Event to law enforcement agencies will only require the industry to notify the state or provincial level law enforcement agency The state or provincial level law enforcement agency will coordinate with local law enforcement to investigate If the state or provincial level law enforcement agency decides federal agency law enforcement or the RCMP should respond and investigate the state or provincial level law enforcement agency will notify and coordinate with the FBI or the RCMP



Entity Experiencing an Actual Impact Event from Attachment 1

Report to Law Enforcement

YESNO


Notification Protocol to State Agency Law

Enforcement

Report Impact Event to NERC Regional Entity

State Agency Law Enforcement coordinates as appropriate with FBI

State Agency Law Enforcement notifies FBI


investigation


Confirmed Sabotage

YESNO

Reporting Hierachy for Impact Event EOP-004-2

FBI Responds and makes notification

to DHS

File DOE Form 417 with Dept of Energy

Procedure to Report to

NERC

Procedure to Report to Law Enforcement

Report Impact Event to NERC Regional

Entity


investigation


State Agency Law Enforcement Investigates


Canadian entities will follow law enforcement protocols applicable in their jurisdictions

NERC Reports Applicable Events to FERC Per Rules

of Procedure NERC Reports Applicable Events to FERC Per Rules of

Procedure



Requirements and Measures R1 The ERO shall establish maintain and utilize a

system for receiving and distributing impact event reports received pursuant to Requirement R6 to applicable government provincial or law enforcement agencies and Registered Entities to enhance and support situational awareness

M1 The ERO shall provide evidence that it established maintained and utilized a system for the distribution of the reports it receives to the various organizations or agencies Such evidence could include but is not limited to dated records indicating that reports were distributed as shown on the submitted report or electronic logs indicating distribution of reports (R1)

Rationale for R1 Every industry participant that owns or operates elements or devices on the grid has a formal or informal process procedure or steps it takes to gather information regarding what happened and why it happened when Impact Events occur This requirement has the Registered Entity establish documentation on how that procedure process or plan is organized For the Impact Event Operating Plan the DSR SDT envisions that Part 12 includes performing sufficient analysis and information gathering to be able to complete the report for reportable Impact Events The main issue is to make sure an entity can a) identify when an Impact Event has occurred and b) be able to gather enough information to complete the report Part 13 could include a process flowchart identification of internal positions to be notified and to make notifications or a list of personnel by name as well as telephone numbers The Impact Event Operating Plan may include but not be limited to the following how the entity is notified of eventrsquos occurrence person(s) initially tasked with the overseeing the assessment or analytical study investigatory steps typically taken and documentation of the assessment remedial action plan



R2 Each ApplicableResponsible Entity identified in Attachment 1 shall have an Impact Event Operating Plan(s) that includes [Violation Risk Factor Medium] [Time Horizon Long-term Planning]

11 An Operating Process for identifying assessing and reporting impact events Impact Events listed in Attachment 1 that includes

12 An Operating Procedure for gathering information for Attachment 2 regarding observed Impact Events listed in Attachment 1

1113 An Operating Process for communicating recognized Impact Events to the following components

12 Method(s) for identifying impact events

13 Method(s) for assessing cause(s) of impact events

14 Method(s) for making internal and external notifications pursuant to Parts 25 and 26

141131 List of internalInternal company personnel responsible for making initial notification(s) pursuant to Parts 25and 26)

15 List of internal company personnel to notify

151132 List of externalExternal organizations to notify to include but not limited to NERCthe Responsible Entitiesrsquo Reliability Coordinator NERC Responsible Entitiesrsquo Regional Entity Law Enforcement and Governmental or Provincial Agencies

1614 MethodProvision(s) for updating the Impact Event Operating Plan when there is a component change within 3090 days of the notification of theany change to its content

17 A provision for updating the Operating Plan based on lessons learned from an exercise or implementation of the Operating Plan within 30 days of identifying the lessons learned

18 A provision for updating the Operating Plan based on applicable lessons learned from the annual NERC report issued pursuant to Requirement R8 within 30 days of NERC publishing lessons learned

Rationale for R2 Every industry participant that owns or operates elements or devices on the grid has a formal or informal process procedure or steps it takes to assess what happened and why it happened when impact events occur This requirement has the Registered Entity establish documentation on how that procedure process or plan is organized For the Operating Plan the DSR SDT envisions that ldquoassessingrdquo includes performing sufficient analysis to be able to complete the report for reportable impact events The main issue is to make sure an entity can a) identify when an impact event has occurred and b) be able to gather enough information to complete the report Parts 33 and 34 include but not limited to operating personnel who could be involved with any aspect of the operating plan The Operating Plan may include but not be limited to the following how the entity is notified of eventrsquos occurrence person(s) initially tasked with the overseeing the assessment or analytical study investigatory steps typically taken and documentation of the assessment remedial action plan



M2 M1 Each ApplicableResponsible Entity shall provide the current in force Impact Event

Operating Plan to the Compliance Enforcement Authority upon request (R2)



R3

R2 Each ApplicableResponsible Entity shall identify and assess initial probable cause of impact events listed in Attachment 1 in accordance with itsimplement its Impact Event Operating Plan documented in Requirement R2R1 for Impact Events listed in Attachment 1 (Parts A and B) [Violation Risk Factor Medium] [Time Horizon Real-time Operations and Same-day Operations]

M3M2 To the extent that an ApplicableResponsible Entity has an impact eventImpact Event on its Facilities the ApplicableResponsible Entity shall provide documentation of its assessment or analysisthe implementation of its Impact Event Operating Plans Such evidence could include but is not limited to operator logs voice recordings or power flow analysis cases (R3)other notations and documents retained by the Registered Entity for each Impact Event

R4 R3 Each ApplicableResponsible Entity

shall conduct a drill exercise or Real-time implementationtest of its Operating PlanProcess for reportingcommunicating recognized Impact Events created pursuant to Requirement R2R1 Part 13 at least annually with no more than 15 calendar months between exercises ortests [Violation Risk Factor Medium] [Time Horizon Long-term Planning]

M3 In the absence of an actual use

Impact Event the Responsible Entity shall provide evidence that it conducted a mock Impact Event and followed its Operating Process for communicating recognized Impact Events created pursuant to Requirement R1 Part 13 The time period between actual and or mock Impact Events shall be no more than 15 months Evidence may include but is not limited to operator logs voice recordings or documentation (R3)

Rationale for R3 The DSR SDT intends for each Responsible Entity to verify that its Operating Process for communicating recognized Impact Events is correct so that the entity can respond appropriately in the case of an actual Impact Event The Responsible Entity may conduct a drill or exercise of its Operating Process for communicating recognized Impact Events as often as it desires but the time period between such drill or exercise can be no longer than 15 months from the previous drillexercise or actual Impact Event (ie if you conducted an exercisedrillactual employment of the Operating Process in January of one year there would be another exercisedrillactual employment by March 31 of the next calendar year)) Multiple exercises in a 15 month period are not a violation of the requirement and would be encouraged to improve reliability

Rationale for R3 The DSR SDT intends for each Applicable Entity to assess the causes of the reportable impact event and gather enough information to complete the report that is required to be filed

Rationale for R4 The DSR SDT intends for each Applicable Entity to conduct a drill or exercise of it Operating Plan as often as merited but no longer than 15 months from the previous exercise to prevent a long cycle of exercises (ie conducting an exercise in January of one year and then December of the next year) Multiple exercises in a 15 month period is not a violation of the requirement and would be encouraged to improve reliability A drill or exercise may be a table-top exercise a simulation or an actual implementation of the Operating Plan



M4 The ApplicableR4 Each Responsible Entity shall provide evidence that it conducted a

drill exercise or Real-time implementation of thereview its Impact Event Operating Plan for reporting as specified in the requirement Such evidence could include but is not limited to a dated exercise scenario with notes on the exercise or operator logs voice recordings or power flow analysis cases for an actual implementation of the Operating Plan (R4)



R5 Each Applicable Entity shall provide training to all internal those personnel who have responsibilities identified in its Operating Plan for reporting pursuant to Requirement R2 subject to the following

51 The training includes the personnel required to respond and their required actions under the Operating Plan

Training conductedthat plan at least once per calendar yearannually with no more than 15 calendar months between trainingreview sessions for personnel with existing responsibilities [Violation Risk Factor Medium] [Time Horizon Long-term Planning ]

52 If the Operating Plan is revised (with the exception of contact information revisions) training shall be conducted within 30 days of the Operating Plan revisions

53 For internal personnel added to the Operating Plan or those with revised responsibilities under the Operating Plan training shall be conducted prior to assuming the responsibilities in the plan

M5 Applicable

M4 Responsible Entities shall provide the actual training materialmaterials presented to verify content and the association between the people listed in the plan and those who participated in the trainingreview documentation showing who was trainedpresent and when internal personnel were trained on the responsibilities in the Operating Plan as well as dates for personnel changes and evidence that the training was conducted following personnel changes (R5)plan

R6R5 Each ApplicableResponsible Entity shall report impact eventsImpact Events in

accordance with itsthe Impact Event Operating Plan created pursuant to Requirement R2R1 and Attachment 1 using the timelines outlinedform in Attachment 12 or the DOE OE-417 reporting form [Violation Risk Factor Medium] [Time Horizon Real-time Operations and Same-day Operations]

M6 RegisteredM5 Responsible Entities shall provide evidence demonstrating the submission of reports using the Operating Planplan created pursuant to Requirement R2 for impact eventsR1 and Attachment 1 using either the form in Attachment 2 or the DOE OE-417 report Such evidence will include a copy of the original impact eventAttachment 2 form or OE-417 report submitted evidence to support the type of impact eventImpact Event

Rationale for R5 The SDT is not prescribing how training is to be conducted and leaves that decision to each Applicable Entity as they best know how to conduct such activities Conduct of an exercise constitutes training for compliance with this requirement For changes to the Operating Plan (53) the training may simply consist of a review of the revised responsibilities and a ldquosign-offrdquo that personnel have reviewed the revisions



experienced the date and time of the impact event Impact Event as well as evidence of report submittal that includes date and time (R6)



R7 The ERO shall annually review and propose revisions to the impact event table (Attachment 1) if warranted based on its analysis of reported impact events Revisions to Attachment 1 shall follow the Reliability Standards Development Procedure

M7 The ERO shall provide evidence that it reviewed the impact event table If applicable the ERO shall provide evidence that it followed the Reliability Standards Development Procedure to propose and implement revisions to Attachment 1 Such evidence may include but not be limited to documentation that compares or assesses the list of impact events (Attachment 1) against the analysis of reported impact events (R7)

R8 The ERO shall publish a quarterly report

of the yearrsquos reportable impact events subject to the following

81 Issued no later than 30 days following the end of the calendar quarter

82 Identifies trends on the BES

83 Identifies threats to the BES

84 Identifies other vulnerabilities to the BES

85 Documents lessons learned

86 Includes recommended actions

M8 The ERO shall provide evidence that it issued a report identifying trends threats or other

vulnerabilities on the bulk electric system at least quarterly Such evidence will include a copy of the report as well as dated evidence of the reportrsquos issuance (R8)

CCoommpplliiaannccee


Rationale for R8 The ERO will analyze Impact Events that are reported through requirement R6 The DSR SDT envisions the ERO issuing reports identifying trends threats or other vulnerabilities when available or at least quarterly The report will include lessons learned and recommended actions (such as mitigation plans) to improve reliability as applicable

Rationale for R7-R8 Some of the concepts contained in Requirements R7 and R8 are contained in the NERC Rules of Procedure section 800 The DSR SDT felt that in order to have a complete standard for reporting impact events that improved reliability there needed to be feedback to industry on a regular basis as well as when issues are discovered The analysis of impact events is crucial and the subsequent dissemination of the results of that analysis must be performed In accordance with Sections 401(2) and 405 of the Rules of Procedures the ERO can be set as an applicable entity in a requirement or standard After careful consideration the DSR SDT believes that these requirements (R7-8) are best applicable to the ERO



bull Regional Entity or

bull For requirements applicable to the ERO an entity contracted to perform an audit

bull If the Responsible Entity works for the Regional Entity then the Regional Entity will establish an agreement with the ERO or another entity approved by the ERO and FERC (ie another Regional Entity) to be responsible for compliance enforcement


bull Compliance Audits bull Self-Certifications bull Spot Checking bull Compliance Violation Investigations bull Self-Reporting bull Complaints

Evidence Retention Each Reliability Coordinator Balancing Authority Transmission Owner Transmission Operator Generator Owner Generator Operator and Distribution ProviderResponsible Entity shall keepretain data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation

The ERO shall retain evidence of Requirements 1 7 and 8 Measures 1 7 and 8 for three calendar years

Each Reliability Coordinator Balancing Authority Transmission Owner Transmission Operator Generator Owner Generator Operator and Distribution Provider shall retain data or evidence of Requirements 2 3 4 and 5 and Measures 2 3 4 and 5 for three calendar years for the duration of any regional or Compliance Enforcement Authority investigation whichever is longer 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

Each Reliability Coordinator Balancing Authority Transmission Owner Transmission Operator Generator Owner Generator Operator and Distribution Provider shall retain data or evidence of Requirement 6 and Measure 6 for three calendar years for the duration of any regional investigation whichever is longer 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

If a Registered Entity is found non-compliant it shall keep information related to the non-compliance until found compliant or for the duration specified above whichever is longer




Additional Compliance Information To be determined

None

Table of Compliance Elements

R Time Horizon

VRF Violation Severity Levels

Lower VSL Moderate VSL High VSL Severe VSL


Medium The Responsible Entity has an Impact Event Operating Plan but failed to include one of Parts 11 through 14

The Responsible Entity has a Impact Event Operating Plan but failed to include two of Parts 11 through 14

The Responsible Entity has an Impact Event Operating Plan but failed to include three of Parts 11 through 14

The Responsible Entity failed to include all of Parts 11 through 14


Medium NA NA NA The Responsible Entity failed to implement its Impact Event Operating Plan for an Impact Event listed in Attachment 1


Medium The Responsible Entity failed to conduct a test of its Operating Process for communicating recognized Impact Events created pursuant to







Requirement R1 Part 13in more than 18 months but less than 21 months


Requirement R1 Part 13 in more than 24 months


Medium The Responsible Entity failed to review its Impact Event Operating Plan with those personnel who have responsibilities identified in that plan l in more than 15 months but less than 18 months



The Responsible Entity failed to review its Impact Event Operating Plan with those personnel who have responsibilities identified in that plan in more than 24 months


Medium The Responsible Entity failed to submit a report in less than 36 hours for an Impact Event requiring reporting within 24 hours in Attachment 1



OR

The Responsible Entity failed to submit a report in more than 1 hour but less than 2 hours for an Impact Event requiring reporting within 1 hour

The Responsible Entity failed to submit a report in more than 60 hours for an Impact Event requiring reporting within 24 hours in Attachment 1

OR

The Responsible Entity failed to submit a report in more than 2 hours for an Impact Event requiring reporting within 1 hour in Attachment 1

OR

The responsible entity



in Attachment 1 failed to submit a report for an Impact Event in Attachment 1

VVaarriiaanncceess

None IInntteerrpprreettaattiioonnss

None



EEOOPP--000044 -- AAttttaacchhmmeenntt 11 IImmppaacctt EEvveennttss TTaabbllee NOTE Under certain adverse conditions eg severe weather it may not be possible to assessreport the damage caused by an impact eventImpact Event and issue a written Impact Event Report within the timing in the table below In such cases the affected ApplicableResponsible Entity shall notify its Regional Entity(ies) and NERC and verbally (e-mail esisacnerccom Facsimile 609-452-9550 Voice 609-452-1422) and provide as much information as is available at that time The affected ApplicableResponsible Entity shall then provide periodic verbal updates until adequate information is available to issue a written Preliminary Impact Event Reportreport




Energy Emergency requiring Public appeal for load reduction

RC BAInitiating entity is responsible for reporting

To reduce consumption in order to maintain the continuity of the BES Each public appeal for load reduction

Within 1 hour of issuing a public appeal

Energy Emergency requiring system-wide voltage reduction

RC TO TOP DP Initiating entity is responsible for reporting

System wide voltage reduction of 3 or more Within 1 hour after occurrenceevent is identifiedinitiated

Energy Emergency requiring manual firm load shedding

Initiating entity is responsible for reporting

Manual firm load shedding ge 100 MW Within 1 hour after event is initiated

Energy Emergency requiringresulting in automatic firm load shedding

RC BA TOP DP Each DP or TOP that experiences the Impact Event

Firm load shedding ge 100 MW (manually or via automatic undervoltage or underfrequency load shedding schemes or SPSRAS)

Within 24 hours1 hour after occurrenceevent is initiated

Voltage Deviations on BES Facilities

Each RC TOP GOP that experiences the Impact Event

plusmn 10 sustained for ge 15 continuous minutes Within 24 hours after 15 minute threshold

Frequency Deviations RC BA plusmn Deviations ge than Frequency Trigger Limit (FTL) more than 15 minutes

Within 24 hours after 15 minute threshold

IROL Violation Each RC TOP that experiences the Impact Event

Operate outside the IROL for time greater than IROL Tv

Within 24 hours after Tv threshold






Loss of Firm load for ge 15 Minutes

Each RC BA TO TOP DP that experiences the Impact Event

bull ge 300 MW for entities with previous yearrsquos demand ge 3000 MW

bull ge 200 MW for all other entities

Within 24 hours1 hour after 15 minute threshold

System Separation (Islanding)

Each RC BA TOP DP that experiences the Impact Event

Each separation resulting in an island of generation and load ge 100 MW


Generation loss Each RC BA GO GOP that experiences the Impact Event

bull ge 2000 MW for entities in the Eastern or Western Interconnection

bull ge 1000 MW for entities in the ERCOT or Quebec Interconnection

bull An entire generating station of ge 5 generators with aggregate capacity of ge 500 MW


Loss of Off-site power to a nuclear generating plant (grid supply)

Each RC BA TO TOP GO GOP that experiences the Impact Event

Affecting a nuclear generating station per the Nuclear Plant Interface Requirement

Report within 24 hours after occurrence

Transmission loss Each RC TO TOP that experiences the Impact Event

bull An entire DC converter station Multiple BES transmission elements (simultaneous or common-mode event)Three or more BES Transmission Elements


Damage or destruction of BES equipment1equipment1

Each RC BA TO TOP GO GOP DP that experiences the Impact Event

Through operational error equipment failure or external cause or intentional or unintentional human action


1BES equipment that i) Affects an IROL ii) Significantly affects the reliability margin of the system (eg has the potential to result in the need for emergency actions) iii) Damaged or destroyed due to intentional or unintentional human action or iv) Do not report copper theft from BES equipment unless it degrades the ability of equipment to operate correctly eg removal of grounding straps rendering protective relaying inoperative






Damage or destruction of Critical Asset


Through operational error equipment failure external cause or intentional or unintentional human action


Damage or destruction of a Critical Cyber Asset


Through intentional or unintentional human action


Examples

a BES equipment that is i A critical asset

ii Affects an IROL iii Significantly affects the reliability margin of the system eg has the potential to result in the need for emergency

actions iv Damaged or destroyed due to a non-environmental external cause

Report copper theft from BES equipment only if it degrades the ability of equipment to operate correctly eg removal of grounding straps rendering protective relaying ineffective



EOP-004 ndash Attachment 1 - Potential Reliability Impact ndash Part B

Event Entity with Reporting

Responsibility


Unplanned Control Center evacuation


Unplanned evacuation from BES control center facility


Fuel supply emergency Each RC BA GO GOP that experiences the potential Impact Event

Affecting BES reliability1reliability2


Loss of off-site power (grid supply)

RC BA TO TOP GO GOP

Affecting a nuclear generating station

report within 1 hour after occurrence

Loss of all monitoring or voice communication capability


Affecting a BES control center for ge 30 continuous minutes

reportReport within 1 hour24 hours after occurrence

Forced intrusion2intrusion3 Each RC BA TO TOP GO GOP that experiences the

At a BES facility reportReport within 24 hours1 hour after occurrenceverification of intrusion

2 Report if problems with the fuel supply chain result in the projected need for emergency actions to manage reliability 3 Report if you cannot reasonably determine likely motivation (ie intrusion to steal copper or spray graffiti is not reportable unless it effects the reliability of the BES)



potential Impact Event

Risk to BES equipment3equipment4


From a non-environmental physical threat

reportReport within 24 hours1 hour after occurrenceidentification

Detection of a cyber intrusion to critical cyber assetsreportable Cyber Security Incident


That meets the criteria in CIP-008 (or its successor)

reportReport within 24 hours1 hour after occurrencedetection

1 Report if problems with the fuel supply chain result in the projected need for emergency actions to manage reliability 2 Report if you cannot reasonably determine likely motivation (ie intrusion to steal copper or spray graffiti is not reportable unless

it effects the reliability of the BES) Examples include a train derailment adjacent to BES equipment that either could have damaged the equipment directly or has the potential to damage the equipment (eg flammable or toxic cargo that could pose fire hazard or could cause evacuation of a BES facility control center)

4 Examples include a train derailment adjacent to BES equipment that either could have damaged the equipment directly or has the potential to damage the equipment (eg flammable or toxic cargo that could pose fire hazard or could cause evacuation of a BES facility control center) and report of suspicious device near BES equipment)



EEOOPP--000022000044 -- AAttttaacchhmmeenntt 22 IImmppaacctt EEvveenntt RReeppoorrttiinngg FFoorrmm This form is to be used to report Impact Events to the ERO NERC will accept the DOE OE-417 form in lieu of this form if the entity is required to submit an OE-417 report Reports should be submitted via one of the following e-mail esisacnerccom Facsimile 609-452-9550


Task Comments

1

Entity filing the report (include company name and Compliance Registration ID number)

2 Date and Time of impact eventImpact Event Date (mmddyyyyyy)

TimeZone

3 Name of contact person Email address Telephone Number

4 Did the impact eventactual or potential Impact Event originate in your system

Actual Impact Event Potential Impact Event

Yes No Unknown

5 Under which NERC function are you reporting (RC TOP BA other)

Formatted Table




Task Comments

6 Brief Description of impact eventactual or potential Impact Event (More detail should be provided in the Sequence of Events section below)

7 Generation tripped off-line

MW Total List units tripped

8 Frequency

Just prior to impact eventImpact Event (Hz) Immediately after impact eventImpact Event

(Hz max) Immediately after impact eventImpact Event

(Hz min)

9 List transmission facilities (lines transformers buses etc) tripped and locked-out

(Specify voltage level of each facility listed)

10 Demand tripped (MW))


Formatted Table




Task Comments

Number of affected customers

Demand lost (MW-Minutes))

11 Restoration Time INITIAL FINAL

Transmission

Generation

Demand

12 Sequence of Events

Sequence of Events of actual or potential Impact Event (if potential Impact Event please describe your assessment of potential impact to BES)

Formatted Table




Task Comments

13 Identify the initial probable cause or known root cause of the impact eventactual or potential Impact Event if known at time of submittal of Part I of this report

14 Identify any protection system misoperation(s))1

15 Additional Information that the helps to further explain the eventactual or potential Impact Event if needed A one-line diagram may be attached if readily available to assist in the evaluation of the event

1 Only applicable if it is part of the impact event the responsible entity is reporting on

Formatted Table




Task Comments

Formatted Table



GGuuiiddeelliinnee aanndd TTeecchhnniiccaall BBaassiiss Disturbance and Sabotage Reporting Standard Drafting Team (Project 2009-01) - Reporting Concepts IInnttrroodduuccttiioonn The SAR for Project 2009-01 Disturbance and Sabotage Reporting was moved forward for standard drafting by the NERC Standards Committee in August of 2009 The Disturbance and Sabotage Reporting Standard Drafting Team (DSR SDT) was formed in late 2009 and is progressing toward developing standards based on the SAR This concepts paper is designed to solicit stakeholder input regarding the proposed reporting concepts that the DSR SDT has developed The standards listed under the SAR are

bull CIP-001 mdash Sabotage Reporting bull EOP-004 mdash Disturbance Reporting

The DSR SDT also proposed to investigate incorporation of the cyber incident reporting aspects of CIP-008 under this project This will be coordinated with the Cyber Security - Order 706 SDT (Project 2008-06) The DSR SDT has reviewed the existing standards the SAR issues from the NERC database and FERC Order 693 Directives to determine a prudent course of action with respect to these standards This concept paper provides stakeholders with a proposed ldquoroad maprdquo that will be used by the DSR SDT in updating or revising CIP-001 and EOP-004 This concept paper provides the background information and thought process of the DSR SDT The proposed changes do not include any real-time operating notifications for the types of events covered by CIP-001 and EOP-004 The real-time reporting requirements are achieved through the RCIS and are covered in other standards (eg EOP-002-Capacity and Energy Emergencies) The proposed standards deal exclusively with after-the-fact reporting The DSR SDT is proposing to consolidate disturbance and event reporting under a single standard These two components and other key concepts are discussed in the following sections



SSuummmmaarryy ooff CCoonncceeppttss aanndd AAssssuummppttiioonnss The Standard Will Require use of a single form to report disturbances and ldquoimpact eventsImpact Eventsrdquo that threaten the reliability of the bulk electric system

bull Provide clear criteria for reporting bull Include consistent reporting timelines bull Identify appropriate applicability including a reporting hierarchy in the case of

disturbance reporting bull Provide clarity around of who will receive the information

The drafting team will explore other opportunities for efficiency such as development of an electronic form and possible inclusion of regional reporting requirements

Discussion of Disturbance Reporting Disturbance reporting requirements currently exist in EOP-004 The current approved definition of Disturbance from the NERC Glossary of Terms is

1 An unplanned event that produces an abnormal system condition

2 Any perturbation to the electric system

3 The unexpected change in ACE that is caused by the sudden failure of generation or interruption of load

Disturbance reporting requirements and criteria are in the existing EOP-004 standard and its attachments The DSR SDT discussed the reliability needs for disturbance reporting and developed the list of impact eventsImpact Events that are to be reported under this standard (attachment 1) Discussion of ldquoimpact eventImpact Eventrdquo Reporting There are situations worthy of reporting because they have the potential to impact reliability The DSR SDT proposes calling such incidents lsquoimpact eventsrsquoImpact Eventsrsquo with the following concept

An impact eventImpact Event is any situation that has the potential to significantly impact the reliability of the Bulk Electric System Such events may originate from malicious intent accidental behavior or natural occurrences

Impact eventEvent reporting facilitates situationalindustry awareness which allows potentially impacted parties to prepare for and possibly mitigate the reliability risk It also provides the raw material in the case of certain potential reliability threats to see emerging patterns Examples of impact eventsImpact Events include

bull Bolts removed from transmission line structures bull Detection of cyber intrusion that meets criteria of CIP-008 or its successor standard bull Forced intrusion attempt at a substation



bull Train derailment near a transmission right-of-way bull Destruction of Bulk Electrical System equipment

What about sabotage One thing became clear in the DSR SDTrsquos discussion concerning sabotage everyone has a different definition The current standard CIP-001 elicited the following response from FERC in FERC Order 693 paragraph 471 which states in part ldquo the Commission directs the ERO to develop the following modifications to the Reliability Standard through the Reliability Standards development process (1) further define sabotage and provide guidance as to the triggering events that would cause an entity to report a sabotage eventrdquo Often the underlying reason for an event is unknown or cannot be confirmed The DSR SDT believes that reporting material risks to the Bulk Electrical System using the impact eventImpact Event categorization it will be easier to get the relevant information for mitigation awareness and tracking while removing the distracting element of motivation The DST SDT discussed the reliability needs for impact eventImpact Event reporting and will consider guidance found in the document ldquoNERC Guideline Threat and Incident Reportingrdquo in the development of requirements which will include clear criteria for reporting Certain types of impact eventsImpact Events should be reported to NERC the Department of Homeland Security (DHS) the Federal Bureau of Investigation (FBI) andor Provincial or local law enforcement Other types of impact eventsImpact Events may have different reporting requirements For example an impact eventImpact Event that is related to copper theft may only need to be reported to the local law enforcement authorities Potential Uses of Reportable Information Event analysis correlation of data and trend identification are a few potential uses for the information reported under this standard As envisioned the standard will only require Functional entities to report the incidents and provide information or data necessary for these analyses Other entities (eg ndash NERC Law Enforcement etc) will be responsible for performing the analyses The NERC Rules of Procedure (section 800) provide an overview of the responsibilities of the ERO in regards to analysis and dissemination of information for reliability Jurisdictional agencies (which may include DHS FBI NERC RE FERC Provincial Regulators and DOE) have other duties and responsibilities Collection of Reportable Information or ldquoOne stop shoppingrdquo The goal of the DSR SDT is to have one reporting form for all functional entities (US Canada Mexico) to submit to NERC Ultimately it may make sense to develop an electronic version to expedite completion sharing and storage Ideally entities would complete a single form which could then be distributed to jurisdictional agencies and functional entities as appropriate Specific reporting forms6

6 The DOE Reporting Form OE-417 is currently a part of the EOP-004 standard If this report is removed from the standard it should be noted that this form is still required by law as noted on the form NOTICE This report is mandatory under Public Law 93-275 Failure to comply may result in criminal fines civil penalties and other

that exist today (ie - OE-417 etc) could be included as part of the



electronic form to accommodate US entities with a requirement to submit the form or may be removed (but still be mandatory for US entities under Public Law 93-275) to streamline the proposed consolidated reliability standard for all North American entities (US Canada Mexico) Jurisdictional agencies may include DHS FBI NERC RE FERC Provincial Regulators and DOE Functional entities may include the RC TOP and BA for situationalindustry awareness Applicability of the standard will be determined based on the specific requirements The DSR SDT recognizes that some regions require reporting of additional information beyond what is in EOP-004 The DSR SDT is planning to update the listing of reportable events from discussions with jurisdictional agencies NERC Regional Entities and stakeholder input There is a possibility that regional differences may still exist The reporting proposed by the DSR SDT is intended to meet the uses and purposes of NERC The DSR SDT recognizes that other requirements for reporting exist (eg DOE-417 reporting) which may duplicate or overlap the information required by NERC To the extent that other reporting is required the DSR SDT envisions that duplicate entry of information is not necessary and the submission of the alternate report will be acceptable to NERC so long as all information required by NERC is submitted For example if the NERC Report duplicates information from the DOE form the DOE report may be included or attached to the NERC report in lieu of entering that information on the NERC report

sanctions as provided by law For the sanctions and the provisions concerning the confidentiality of information submitted on this form see General Information portion of the instructions Title 18 USC 1001 makes it a criminal offense for any person knowingly and willingly to make to any Agency or Department of the United States any false fictitious or fraudulent statements as to any matter within its jurisdiction



A Introduction 1 Title Sabotage Reporting 2 Number CIP-001-1 3 Purpose Disturbances or unusual occurrences suspected or determined to be

caused by sabotage shall be reported to the appropriate systems governmental agencies and regulatory bodies

4 Applicability 41 Reliability Coordinators 42 Balancing Authorities 43 Transmission Operators 44 Generator Operators 45 Load Serving Entities


B Requirements R1 Each Reliability Coordinator Balancing Authority Transmission Operator Generator

Operator and Load Serving Entity shall have procedures for the recognition of and for making their operating personnel aware of sabotage events on its facilities and multi-site sabotage affecting larger portions of the Interconnection

R2 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall have procedures for the communication of information concerning sabotage events to appropriate parties in the Interconnection

R3 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall provide its operating personnel with sabotage response guidelines including personnel to contact for reporting disturbances due to sabotage events

R4 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall establish communications contacts as applicable with local Federal Bureau of Investigation (FBI) or Royal Canadian Mounted Police (RCMP) officials and develop reporting procedures as appropriate to their circumstances

C Measures M1 Each Reliability Coordinator Balancing Authority Transmission Operator Generator

Operator and Load Serving Entity shall have and provide upon request a procedure (either electronic or hard copy) as defined in Requirement 1

M2 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall have and provide upon request the procedures or guidelines that will be used to confirm that it meets Requirements 2 and 3



M3 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load Serving Entity shall have and provide upon request evidence that could include but is not limited to procedures policies a letter of understanding communication records or other equivalent evidence that will be used to confirm that it has established communications contacts with the applicable local FBI or RCMP officials to communicate sabotage events (Requirement 4)


11 Compliance Monitoring Responsibility Regional Reliability Organizations shall be responsible for compliance monitoring

12 Compliance Monitoring and Reset Time Frame One or more of the following methods will be used to verify compliance






13 Data Retention Each Reliability Coordinator Transmission Operator Generator Operator Distribution Provider and Load Serving Entity shall have current in-force documents available as evidence of compliance as specified in each of the Measures

If an entity is found non-compliant the entity shall keep information related to the non-compliance until found compliant or for two years plus the current year whichever is longer






None

2 Levels of Non-Compliance 21 Level 1 There shall be a separate Level 1 non-compliance for every one of the

following requirements that is in violation

211 Does not have procedures for the recognition of and for making its operating personnel aware of sabotage events (R1)

212 Does not have procedures or guidelines for the communication of information concerning sabotage events to appropriate parties in the Interconnection (R2)

213 Has not established communications contacts as specified in R4


23 Level 3 Has not provided its operating personnel with sabotage response procedures or guidelines (R3)

24 Level 4Not applicable

E Regional Differences None indicated




Errata

1 November 1 2006

Adopted by Board of Trustees Amended



A Introduction 1 Title Disturbance Reporting 2 Number EOP-004-1 3 Purpose Disturbances or unusual occurrences that jeopardize the operation of the

Bulk Electric System or result in system equipment damage or customer interruptions need to be studied and understood to minimize the likelihood of similar events in the future

4 Applicability 41 Reliability Coordinators 42 Balancing Authorities 43 Transmission Operators 44 Generator Operators 45 Load Serving Entities 46 Regional Reliability Organizations


B Requirements R1 Each Regional Reliability Organization shall establish and maintain a Regional

reporting procedure to facilitate preparation of preliminary and final disturbance reports

R2 A Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall promptly analyze Bulk Electric System disturbances on its system or facilities

R3 A Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity experiencing a reportable incident shall provide a preliminary written report to its Regional Reliability Organization and NERC

R31 The affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall submit within 24 hours of the disturbance or unusual occurrence either a copy of the report submitted to DOE or if no DOE report is required a copy of the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Report form Events that are not identified until some time after they occur shall be reported within 24 hours of being recognized

R32 Applicable reporting forms are provided in Attachments 1-EOP-004 and 2-EOP-004

R33 Under certain adverse conditions eg severe weather it may not be possible to assess the damage caused by a disturbance and issue a written Interconnection Reliability Operating Limit and Preliminary Disturbance Report within 24 hours In such cases the affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall promptly notify its Regional Reliability Organization(s) and NERC and verbally provide as much information as is available at that



time The affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall then provide timely periodic verbal updates until adequate information is available to issue a written Preliminary Disturbance Report

R34 If in the judgment of the Regional Reliability Organization after consultation with the Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity in which a disturbance occurred a final report is required the affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity shall prepare this report within 60 days As a minimum the final report shall have a discussion of the events and its cause the conclusions reached and recommendations to prevent recurrence of this type of event The report shall be subject to Regional Reliability Organization approval

R4 When a Bulk Electric System disturbance occurs the Regional Reliability Organization shall make its representatives on the NERC Operating Committee and Disturbance Analysis Working Group available to the affected Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity immediately affected by the disturbance for the purpose of providing any needed assistance in the investigation and to assist in the preparation of a final report

R5 The Regional Reliability Organization shall track and review the status of all final report recommendations at least twice each year to ensure they are being acted upon in a timely manner If any recommendation has not been acted on within two years or if Regional Reliability Organization tracking and review indicates at any time that any recommendation is not being acted on with sufficient diligence the Regional Reliability Organization shall notify the NERC Planning Committee and Operating Committee of the status of the recommendation(s) and the steps the Regional Reliability Organization has taken to accelerate implementation

C Measures M1 The Regional Reliability Organization shall have and provide upon request as

evidence its current regional reporting procedure that is used to facilitate preparation of preliminary and final disturbance reports (Requirement 1)

M2 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load-Serving Entity that has a reportable incident shall have and provide upon request evidence that could include but is not limited to the preliminary report computer printouts operator logs or other equivalent evidence that will be used to confirm that it prepared and delivered the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Reports to NERC within 24 hours of its recognition as specified in Requirement 31

M3 Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator andor Load Serving Entity that has a reportable incident shall have and provide upon request evidence that could include but is not limited to operator logs voice recordings or transcripts of voice recordings electronic communications or other equivalent evidence that will be used to confirm that it provided information verbally as time permitted when system conditions precluded the preparation of a report in 24 hours (Requirement 33)




11 Compliance Monitoring Responsibility NERC shall be responsible for compliance monitoring of the Regional Reliability Organizations

Regional Reliability Organizations shall be responsible for compliance monitoring of Reliability Coordinators Balancing Authorities Transmission Operators Generator Operators and Load-serving Entities

12 Compliance Monitoring and Reset Time Frame One or more of the following methods will be used to assess compliance






13 Data Retention Each Regional Reliability Organization shall have its current in-force regional reporting procedure as evidence of compliance (Measure 1)

Each Reliability Coordinator Balancing Authority Transmission Operator Generator Operator andor Load Serving Entity that is either involved in a Bulk Electric System disturbance or has a reportable incident shall keep data related to the incident for a year from the event or for the duration of any regional investigation whichever is longer (Measures 2 through 4)

If an entity is found non-compliant the entity shall keep information related to the noncompliance until found compliant or for two years plus the current year whichever is longer





14 Additional Compliance Information See Attachments

- EOP-004 Disturbance Reporting Form

- Table 1 EOP-004

2 Levels of Non-Compliance for a Regional Reliability Organization 21 Level 1 Not applicable



24 Level 4 No current procedure to facilitate preparation of preliminary and final disturbance reports as specified in R1

3 Levels of Non-Compliance for a Reliability Coordinator Balancing Authority Transmission Operator Generator Operator and Load- Serving Entity 31 Level 1 There shall be a level one non-compliance if any of the following

conditions exist

311 Failed to prepare and deliver the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Reports to NERC within 24 hours of its recognition as specified in Requirement 31

312 Failed to provide disturbance information verbally as time permitted when system conditions precluded the preparation of a report in 24 hours as specified in R33

313 Failed to prepare a final report within 60 days as specified in R34




E Regional Differences None identified



0 May 23 2005 Fixed reference to attachments 1-EOP-004-0 and 2-EOP-004-0 Changed chart title 1-FAC-004-0 to 1-EOP-004-0 Fixed title of Table 1 to read 1-EOP-004-0 and fixed font

Errata

0 July 6 2005 Fixed email in Attachment 1-EOP-004-0 from infonerccom to esisacnerccom

Errata



0 July 26 2005 Fixed Header on page 8 to read EOP-004-0

Errata


Errata

1 November 1 2006

Adopted by Board of Trustees Revised



Attachment 1-EOP-004 NERC Disturbance Report Form

Introduction These disturbance reporting requirements apply to all Reliability Coordinators Balancing Authorities Transmission Operators Generator Operators and Load Serving Entities and provide a common basis for all NERC disturbance reporting The entity on whose system a reportable disturbance occurs shall notify NERC and its Regional Reliability Organization of the disturbance using the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Report forms Reports can be sent to NERC via email (esisacnerccom) by facsimile (609-452-9550) using the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Report forms If a disturbance is to be reported to the US Department of Energy also the responding entity may use the DOE reporting form when reporting to NERC Note All Emergency Incident and Disturbance Reports (Schedules 1 and 2) sent to DOE shall be simultaneously sent to NERC preferably electronically at esisacnerccom The NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Reports are to be made for any of the following events 1 The loss of a bulk power transmission component that significantly affects the integrity of

interconnected system operations Generally a disturbance report will be required if the event results in actions such as a Modification of operating procedures b Modification of equipment (eg control systems or special protection systems) to

prevent reoccurrence of the event c Identification of valuable lessons learned d Identification of non-compliance with NERC standards or policies e Identification of a disturbance that is beyond recognized criteria ie three-phase fault

with breaker failure etc f Frequency or voltage going below the under-frequency or under-voltage load shed

points 2 The occurrence of an interconnected system separation or system islanding or both 3 Loss of generation by a Generator Operator Balancing Authority or Load-Serving Entity

2000 MW or more in the Eastern Interconnection or Western Interconnection and 1000 MW or more in the ERCOT Interconnection

4 Equipment failuressystem operational actions which result in the loss of firm system demands for more than 15 minutes as described below a Entities with a previous year recorded peak demand of more than 3000 MW are

required to report all such losses of firm demands totaling more than 300 MW b All other entities are required to report all such losses of firm demands totaling more

than 200 MW or 50 of the total customers being supplied immediately prior to the incident whichever is less

5 Firm load shedding of 100 MW or more to maintain the continuity of the bulk electric system



6 Any action taken by a Generator Operator Transmission Operator Balancing Authority or Load-Serving Entity that results in a Sustained voltage excursions equal to or greater than plusmn10 or b Major damage to power system components or c Failure degradation or misoperation of system protection special protection schemes

remedial action schemes or other operating systems that do not require operator intervention which did result in or could have resulted in a system disturbance as defined by steps 1 through 5 above

7 An Interconnection Reliability Operating Limit (IROL) violation as required in reliability standard TOP-007

8 Any event that the Operating Committee requests to be submitted to Disturbance Analysis Working Group (DAWG) for review because of the nature of the disturbance and the insight and lessons the electricity supply and delivery industry could learn



NERC Interconnection Reliability Operating Limit and Preliminary Disturbance

Report

Check here if this is an Interconnection Reliability Operating Limit (IROL) violation report

1 Organization filing report

2 Name of person filing report

3 Telephone number

4 Date and time of disturbance Date(mmddyy)

TimeZone

5 Did the disturbance originate in your system

Yes No

6 Describe disturbance including cause equipment damage critical services interrupted system separation key scheduled and actual flows prior to disturbance and in the case of a disturbance involving a special protection or remedial action scheme what action is being taken to prevent recurrence

7 Generation tripped MW Total

List generation tripped

8 Frequency Just prior to disturbance (Hz)

Immediately after disturbance (Hz max)

Immediately after disturbance (Hz min)

9 List transmission lines tripped (specify voltage level of each line)

10 Demand tripped (MW)

Number of affected Customers




Demand lost (MW-Minutes)

11 Restoration time INITIAL FINAL

Transmission

Generation

Demand



Attachment 2-EOP-004 US Department of Energy Disturbance Reporting Requirements

Introduction The US Department of Energy (DOE) under its relevant authorities has established mandatory reporting requirements for electric emergency incidents and disturbances in the United States DOE collects this information from the electric power industry on Form EIA-417 to meet its overall national security and Federal Energy Management Agencyrsquos Federal Response Plan (FRP) responsibilities DOE will use the data from this form to obtain current information regarding emergency situations on US electric energy supply systems DOErsquos Energy Information Administration (EIA) will use the data for reporting on electric power emergency incidents and disturbances in monthly EIA reports In addition the data may be used to develop legislative recommendations reports to the Congress and as a basis for DOE investigations following severe prolonged or repeated electric power reliability problems Every Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity must use this form to submit mandatory reports of electric power system incidents or disturbances to the DOE Operations Center which operates on a 24-hour basis seven days a week All other entities operating electric systems have filing responsibilities to provide information to the Reliability Coordinator Balancing Authority Transmission Operator Generator Operator or Load Serving Entity when necessary for their reporting obligations and to file form EIA-417 in cases where these entities will not be involved EIA requests that it be notified of those that plan to file jointly and of those electric entities that want to file separately Special reporting provisions exist for those electric utilities located within the United States but for whom Reliability Coordinator oversight responsibilities are handled by electrical systems located across an international border A foreign utility handling US Balancing Authority responsibilities may wish to file this information voluntarily to the DOE Any US-based utility in this international situation needs to inform DOE that these filings will come from a foreign-based electric system or file the required reports themselves Form EIA-417 must be submitted to the DOE Operations Center if any one of the following applies (see Table 1-EOP-004-0 mdash Summary of NERC and DOE Reporting Requirements for Major Electric System Emergencies) 1 Uncontrolled loss of 300 MW or more of firm system load for more than 15 minutes from a

single incident 2 Load shedding of 100 MW or more implemented under emergency operational policy 3 System-wide voltage reductions of 3 percent or more 4 Public appeal to reduce the use of electricity for purposes of maintaining the continuity of the

electric power system 5 Actual or suspected physical attacks that could impact electric power system adequacy or

reliability or vandalism which target components of any security system Actual or suspected cyber or communications attacks that could impact electric power system adequacy or vulnerability



6 Actual or suspected cyber or communications attacks that could impact electric power system adequacy or vulnerability

7 Fuel supply emergencies that could impact electric power system adequacy or reliability 8 Loss of electric service to more than 50000 customers for one hour or more 9 Complete operational failure or shut-down of the transmission andor distribution electrical

system The initial DOE Emergency Incident and Disturbance Report (form EIA-417 ndash Schedule 1) shall be submitted to the DOE Operations Center within 60 minutes of the time of the system disruption Complete information may not be available at the time of the disruption However provide as much information as is known or suspected at the time of the initial filing If the incident is having a critical impact on operations a telephone notification to the DOE Operations Center (202-586-8100) is acceptable pending submission of the completed form EIA-417 Electronic submission via an on-line web-based form is the preferred method of notification However electronic submission by facsimile or email is acceptable An updated form EIA-417 (Schedule 1 and 2) is due within 48 hours of the event to provide complete disruption information Electronic submission via facsimile or email is the preferred method of notification Detailed DOE Incident and Disturbance reporting requirements can be found at httpwwweiadoegovcneafelectricitypageform_417html



Table 1-EOP-004-0 Summary of NERC and DOE Reporting Requirements for Major Electric System

Emergencies Incident No Incident Threshold Report

Required Time

1 Uncontrolled loss of Firm System Load

ge 300 MW ndash 15 minutes or more


1 hour 48 hour

2 Load Shedding ge 100 MW under emergency operational policy


1 hour 48 hour

3 Voltage Reductions 3 or more ndash applied system-wide


1 hour 48 hour

4 Public Appeals Emergency conditions to reduce demand


1 hour 48 hour

5 Physical sabotage terrorism or vandalism

On physical security systems ndash suspected or real


1 hour 48 hour

6 Cyber sabotage terrorism or vandalism

If the attempt is believed to have or did happen


1 hour 48 hour

7 Fuel supply emergencies

Fuel inventory or hydro storage levels le 50 of normal


1 hour 48 hour

8 Loss of electric service ge 50000 for 1 hour or more


1 hour 48 hour

9

Complete operation failure of electrical system

If isolated or interconnected electrical systems suffer total electrical system collapse


1 hour 48 hour

All DOE EIA-417 Schedule 1 reports are to be filed within 60-minutes after the start of an incident or disturbance All DOE EIA-417 Schedule 2 reports are to be filed within 48-hours after the start of an incident or disturbance



All entities required to file a DOE EIA-417 report (Schedule 1 amp 2) shall send a copy of these reports to NERC simultaneously but no later than 24 hours after the start of the incident or disturbance Incident No Incident Threshold Report

Required Time

1 Loss of major system component

Significantly affects integrity of interconnected system operations


24 hour 60 day

2

Interconnected system separation or system islanding

Total system shutdown Partial shutdown separation or islanding


24 hour 60 day

3 Loss of generation ge 2000 ndash Eastern Interconnection ge 2000 ndash Western Interconnection ge 1000 ndash ERCOT Interconnection


24 hour 60 day

4 Loss of firm load ge15-minutes

Entities with peak demand ge3000 loss ge300 MW All others ge200MW or 50 of total demand


24 hour 60 day

5 Firm load shedding

ge100 MW to maintain continuity of bulk system


24 hour 60 day

6

System operation or operation actions resulting in

bull Voltage excursions ge10 bull Major damage to system

components bull Failure degradation or

misoperation of SPS


24 hour 60 day

7 IROL violation Reliability standard TOP-007


72 hour 60 day

8 As requested by ORS Chairman

Due to nature of disturbance amp usefulness to industry (lessons learned)


24 hour 60 day

All NERC Operating Security Limit and Preliminary Disturbance reports will be filed within 24 hours after the start of the incident If an entity must file a DOE EIA-417 report on an incident which requires a NERC Preliminary report the Entity may use the DOE EIA-417 form for both DOE and NERC reports Any entity reporting a DOE or NERC incident or disturbance has the responsibility to also notify its Regional Reliability Organization



Project 2009-01 Disturbance and Sabotage Reporting Implementation Plan Implementation Plan for EOP-004-2 - Impact Event Assessment Analysis and Reporting Prerequisite Approvals None Revisions to Approved Standards and Definitions Retire all requirements of EOP-004-1 and CIP-001-1 Compliance with the Standard The following entities are responsible for being compliant with all requirements of EOP-004-2

bull Reliability Coordinator bull Balancing Authority bull Load-serving Entity bull Interchange Authority bull Transmission Service Provider bull Transmission Owner bull Transmission Operator bull Generator Owner bull Generator Operator bull Distribution Provider

Effective Date The standard shall become effective on the first calendar day of the third calendar quarter after the date of the order providing applicable regulatory approval In those jurisdictions where no regulatory approval is required the standard shall become effective on the first calendar day of the third calendar quarter after Board of Trustees adoption


Project 2009-01 Disturbance and Sabotage Reporting Formal Comment Period Open March 9 ndash April 8 2011 Now available at httpwwwnerccomfilezstandardsProject2009-01_Disturbance_Sabotage_Reportinghtml Formal 30-day Comment Period Open through 8 pm on April 8 2011 The Disturbance and Sabotage Reporting SDT has posted a revised draft of EOP-004-2 mdash Impact Event Reporting along with the associated implementation plan and a redline of EOP-004-2 showing changes made since an informal comment period for this project concluded in October 2010 These documents are posted for a 30-day formal comment period The drafting team proposes to retire CIP-001-1 and incorporate its requirements into EOP-004-2 As a result the changes to EOP-004 are so extensive that a redline showing changes against the last approved version would be impractical For reference the last approved versions of EOP-004 and CIP-001 have been posted Instructions Please use this electronic form to submit comments If you experience any difficulties in using the electronic form please contact Monica Benson at monicabensonnercnet An off-line unofficial copy of the comment form is posted on the project page httpwwwnerccomfilezstandardsProject2009-01_Disturbance_Sabotage_Reportinghtml Next Steps The drafting team will consider all comments and determine whether to make additional changes to the standard The team will post its response to comments and if changes are made to the standard and supporting documents submit the revised documents for quality review prior to ballot Project Background Stakeholders have indicated that identifying potential acts of ldquosabotagerdquo is difficult to do in real time and additional clarity is needed to identify thresholds for reporting potential acts of sabotage in CIP-001-1 Stakeholders have also reported that EOP-004-1 has some requirements that reference out-of-date Department of Energy forms making the requirements ambiguous EOP-004-1 also has some lsquofill-in-the-blankrsquo components to eliminate The project will include addressing previously identified stakeholder concerns and FERC directives will bring the standards into conformance with the latest approved version of the ERO Rules of Procedure and may include other improvements to the standards deemed appropriate by the drafting team with the consensus of stakeholders consistent with establishing high quality enforceable and technically sufficient bulk power system reliability standards

Standards Process The Standard Processes Manual contains all the procedures governing the standards development process The success of the NERC standards development process depends on stakeholder participation We extend our thanks to all those who participate




From Guy V ZitoTo rsballotCc Lee R PedowiczSubject FW Comment Form--Project 2010-11 - TPL Table 1 OrderDate Wednesday January 05 2011 94852 AMAttachments LP--Project_2010-11_Unofficial_Comment_Form-1-5-11doc

NPCC Members of the NERC Registered Ballot Body Attached is a form containing comments submitted with NPCCs Affirmative Vote toaccept the standard Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

Unofficial Comment Form for TPL Table 1 Order (Project 2010-11)

Unofficial Comment Form for TPL Table 1 Order (Project 2010-11)

Please DO NOT use this form to submit comments on the 3rd posting for Project 2010-11 TPL Table 1 Order Please use the electronic comment form posted on the following project page

httpwwwnerccomfilezstandardsProject2010-11_TPL_Table-1_Orderhtml

The electronic comment form must be completed by January 3 2011 This is a 45-day formal comment period

If you have questions please contact Ed Dobrowolski at
eddobrowolskinercnet or by telephone at 609-947-3673

The Standard Drafting Team (SDT) posted Table I footnote lsquobrsquo for an informal comment period from September 8 2010 through October 8 2010 Industry response was divided in relation to support for the proposed footnote lsquobrsquo Although there were a number of supporters for the proposed footnote they were outnumbered by the commenters who did not support the footnote text for various reasons and offered their views and concerns

The SDT carefully considered the feedback provided including minority opinions such as not allowing Demand interruption at all and has made clarifying revisions to the footnote lsquobrsquo text

The revisions made to footnote lsquobrsquo following the informal comment period are shown below

b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Demand following Contingency events However it is recognized that Demand will be interrupted if it is directly served by the elements removed from service as a result of the Contingency Furthermore in limited circumstances Demand may need to be interrupted to address BES performance requirements When interruption of Demand is utilized within the planning process to address BES performance requirements such interruption is limited to

middot

middot Interruptible Demand or Demand-Side Management

middot Circumstances where the use of Demand interruption are documented including alternatives evaluated and where the Demand interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments

Please Enter All Comments in Simple Text Format

Insert a ldquocheckrdquo mark in the appropriate boxes by double-clicking the gray areas

1 The SDT is proposing a revision to footnote lsquobrsquo in the TPL tables to comply with a FERC directive which required the ERO to clarify TPL-002-0 Table 1 - footnote lsquobrsquo regarding the planned or controlled interruption of electric supply where a single contingency occurs on a transmission system Do you agree with the proposed changes and if not please provide specific reasons for your disagreement

FORMCHECKBOX Yes

FORMCHECKBOX No

Comments There is concern with the use of the term Demand It is unclear throughout the footnote whether or not the term Demand includes Interruptible Demand or Demand-Side Management It is suggested that interruption of Demand be clarified to not include Interruptible Demand or Demand-Side Management to more clearly show the permitted use of Load shedding It is unclear whether the second bullet includes Demand which is interrupted by the elements removed from service Clarification should be made such that Demand which is interrupted by the elements removed from service should not be included in this bullet

Language that mitigation of Load andor Demand interruption should be pursued within the planning process should be reinstated as reinforcement of a Transmission Providersrsquo planning obligations to their load customers and system operations Footnote lsquobrsquo should be made to read as follows

b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of Load andor Demand following Contingency events Interruption of Load andor Demand is discouraged and all measures to mitigate such interruption should be pursued within the planning process However it is recognized that Load andor Demand will be interrupted if it is directly served by the elements automatically removed from service by the Protection System as a result of a Contingency Furthermore in extraordinary circumstances within the planning process Load andor Demand may need to be interrupted to address BES performance requirements When interruption of Load andor Demand is utilized within the planning process to address BES performance requirements such interruption is limited to

middot Circumstances where the use of Load andor Demand interruption are documented including alternatives evaluated and where the Load andor Demand interruption is made available for review in an open and transparent stakeholder process

If Load andor Demand interruption is necessary planning should indicate the amount needed and not specify how it would be obtained What Load andor Demand is interrupted is an operational decision

Additional comments not included in the material listed for footnote lsquobrsquo on the Comment Form In the paragraph below the bullets in footnote lsquobrsquo confusion is introduced through the use of the term ldquofirm Demandrdquo It is unclear how this is different than the defined term ldquoFirm Demandrdquo and what the implications of the term ldquofirm Demandrdquo are This footnote should not discourage such adjustments which actually increase the reliability of service to end users The last sentence of footnote lsquobrsquo is unnecessary and should be deleted It is never acceptable to cause reliability concerns in another area while addressing your own

116-390 Village BoulevardPrinceton New Jersey 08540-5721


3

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Recirculation Ballot Window Open January 26-February 5 2011 - Project 2010-11 TPL Table 1 OrderDate Wednesday January 26 2011 102627 AM

Standards AnnouncementRecirculation Ballot Window Open January 26-February 5 2011Project 2010-11 TPL Table 1 Order Now available at httpsstandardsnercnetCurrentBallotsaspx A recirculation ballot window for standards TPL-001-1 TPL-002-1b TPL-003-1a and TPL-004-1 is open until 8 pm Eastern onSaturday February 5 2011 InstructionsMembers of the ballot pool associated with this project may log in and submit their votes from the following pagehttpsstandardsnercnetCurrentBallotsaspx Ballot ProcessThe Standards Committee encourages all members of the ballot pool to review the consideration of comments submitted during the lastballot window In the recirculation ballot votes are counted by exception only mdash if a ballot pool member does not submit a revision to thatmemberrsquos original vote the vote remains the same as in the first ballot Members of the ballot pool may

Reconsider and change their votes from the first ballot

Vote in the second ballot even if they did not vote on the first ballot

Take no action if they do not want to change their original vote

Additional InformationThe Standard Processes Manual allows drafting teams to make changes following an initial or successive ballot with a goal of improving thequality of a standard provided those changes do not alter the applicability or scope of the proposed standard Following the initial ballot theProject 2010-11 made minor changes to the structure of footnote lsquobrsquo in all of the standards and corrected capitalization of NERC Glossaryterms The standards (clean versions and redlines against the last posted and last approved versions) have been posted on the project page Next StepsVoting results will be posted and announced after the ballot window closes If approved the standards and associated implementation planwill be submitted to the Board of Trustees BackgroundFERC Order RM06-16-009 requires the ERO to clarify TPL-002-0 Table 1 - footnote lsquobrsquo regarding the planned or controlled interruptionof electric supply where a single contingency occurs on a transmission system and originally directed NERC to file the revised standards byJune 30 2010 To meet this directive a proposed revision was posted for ldquoUrgent Actionrdquo and balloted from May 17-27 2010 Theproposed revision achieved a quorum (84) and almost enough affirmative votes (64) to achieve weighted segment approval howevermany balloters provided comments indicating the need for additional modifications Following the initial ballot FERC extended the duedate to March 31 2011 thus the project is no longer considered ldquoUrgent Actionrdquo Because Table 1 appears in TPL-001 TPL-002 TPL-003 and TPL-004 the change is reflected in all four standards





More details may be found on the project pagehttpwwwnerccomfilezstandardsProject2010-11_TPL_Table-1_Orderhtml Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Monica BensonTo monicabensonnercnetSubject Standards Announcement Recirculation Ballot Results | Project 2010-11 TPL Table 1 Footnote BDate Thursday February 10 2011 111522 AM

Standards AnnouncementProject 2010-11 TPL Table 1 Footnote BRecirculation Ballot Results Now available at httpsstandardsnercnetBallotsaspx A recirculation ballot of Table 1 footnote lsquobrsquo in TPL-001-1 through TPL-004-1 ended on February 5 2011 The standards were approved Voting statistics are listed below and the Ballot Results Web page provides a link to the detailed results Quorum 9361 Approval 8654 BackgroundFERC Order RM06-16-009 requires the ERO to clarify TPL-002-0 Table 1 - footnote lsquobrsquo regarding the planned or controlled interruptionof electric supply where a single contingency occurs on a transmission system and originally directed NERC to file the revised standardsby June 30 2010 To meet this directive a proposed revision was posted for ldquoUrgent Actionrdquo and balloted from May 17-27 2010 Theproposed revision achieved a quorum (84) and almost enough affirmative votes (64) to achieve weighted segment approval howevermany balloters provided comments indicating the need for additional modifications Following the initial ballot FERC extended the duedate to March 31 2011 thus the project is no longer considered ldquoUrgent Actionrdquo Because Table 1 appears in TPL-001 TPL-002 TPL-003 and TPL-004 the change is reflected in all four standards





More details may be found on the project pagehttpwwwnerccomfilezstandardsProject2010-11_TPL_Table-1_Orderhtml Next StepsThe standards will go to the Board of Trustees for adoption Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Guy V ZitoTo rscSubject FW Standards Announcement Project 2007-07 Transmission Vegetation Management - Successive Ballot ResultsDate Thursday March 03 2011 120535 PM

RSC The below successive ballot passed but will go to a recirc ballot after comments are answered Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica Benson [MonicaBensonnercnet]Sent Thursday March 03 2011 1147 AMTo monicabensonnercnetSubject Standards Announcement Project 2007-07 Transmission Vegetation Management - Successive Ballot Results

Standards AnnouncementProject 2007-07 Transmission Vegetation ManagementSuccessive Ballot Results Now available at httpsstandardsnercnetBallotsaspx Ballot Results for Revisions to FAC-003A successive ballot on revisions to FAC-003 - Transmission Vegetation Management and a concurrent non-binding poll of associatedVRFs and VSLs concluded on February 28 2011 Voting statistics are listed below and the Ballot Results Web page provides a link to the detailed resultsQuorum 7928 Approval 7934 Violation Risk Factor (VRF) and Violation Severity Level (VSL) Non-binding Poll ResultsFor the non-binding poll of VRFs and VSLs 77 of those who registered to participate provided an opinion 79 of those who providedan opinion indicated support for the VRFs and VSLs that were proposed Next StepsThe drafting team will post its consideration of all comments (those submitted with a comment form and those submitted with a ballot)

BackgroundFAC-003-1 is being revised to address several fill-in-the-blank requirements directives from Order 693 and issues raised by stakeholders An initial ballot closed in July 2010 and achieved a quorum of 8618 and an approval of 6593 The drafting team has posted itsconsideration of comments received both those submitted with a ballot as well as those submitted with a comment form In addition aQuality Review was conducted in November 2010 and the drafting team revised the draft standard and technical reference in response tocomments and input from the Quality Review Further details are available on the project page httpwwwnerccomfilezstandardsVegetation-Management_Project_2007-7html

Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Guy V ZitoTo rsballotCc rscSubject Project 2007-07 ― Vegetation Management ― FAC-003Date Tuesday February 22 2011 81239 AMImportance High

NPCC Members of the NERC Registered Ballot Body The Regional Standards Committee has reviewed and sought opinions from subject matter expertsin the northeast on the subject draft standard currently posted for ballot though Feb 28 2011 The RSC recommends an affirmative or YES vote however the group will be submitting somecomments requesting that the Drafting Team clarify the term ldquoencroachmentrdquo

This is a ldquosuccessiverdquo ballot Even if no substantive revision is needed in order to obtain a passingvote tally there will be a recirculation ballot If however the comments submitted indicate a needto draft a substantially revised standard there will be another successive ballot conducted TheRSC will keep you informed Thank-you Guy V ZitoAsst Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Successive Ballot and Non-binding Poll Open | Project 2007-07 Vegetation ManagementDate Friday February 18 2011 104229 AM

Standards AnnouncementSuccessive Ballot and Non-binding Poll OpenProject 2007-07 ndash Vegetation ManagementFebruary 18 ndash February 28 2011 Now available at httpsstandardsnercnetCurrentBallotsaspx Project 2007-07 ndash Vegetation ManagementA successive ballot window for FAC-003-2 ndash Transmission Vegetation Management and its associated implementation plan is open through8 pm on February 28 2011 In addition members of this ballot pool will be able to vote in a concurrent non-binding poll on the standardrsquos Violation Risk Factors(VRFs) and Violation Severity Levels (VSLs) Members who joined the ballot pool to vote on the standard were automatically entered in aseparate pool to participate in the non-binding poll for the VRFs and VSLs The non-binding poll will appear in the list of current ballotsand is labeled accordingly InstructionsMembers of the ballot pool associated with this project may log in and submit their votes from the following pagehttpsstandardsnercnetCurrentBallotsaspx BackgroundFAC-003-1 is being revised to address several fill-in-the-blank requirements directives from Order 693 and issues raised by stakeholders An initial ballot closed in July 2010 and achieved a quorum of 8618 and an approval of 6593 The drafting team has posted itsconsideration of comments received both those submitted with a ballot as well as those submitted with a comment form In addition aQuality Review was conducted in November 2010 and the drafting team revised the draft standard and technical reference in response tocomments and input from the Quality Review Documents for this project including clean and redline to the last posted versions of the standard implementation plan and technicalreference and an unofficial copy of the questions listed in the comment forms are posted on the project web page athttpwwwnerccomfilezstandardsVegetation-Management_Project_2007-7html Next StepsVoting results will be posted and announced after the ballot window closes and the drafting team will consider all comments includingthose submitted with a comment form and those submitted with a ballot Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Guy V ZitoTo rscSubject FW Standards Announcement Project 2006-06 ndash Reliability Coordination | Initial Ballot ResultsDate Wednesday March 09 2011 44527 PM

FYI Ballot failed The DT will revise the standard based on comments submitted with the ballots and conduct a successive ballot I willfollow this closely and keep you all informed You will recall the issue of contention in this project was pertaining to use and meaning ofthe term Directive Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica Benson [MonicaBensonnercnet]Sent Wednesday March 09 2011 403 PMTo monicabensonnercnetSubject Standards Announcement Project 2006-06 ndash Reliability Coordination | Initial Ballot Results

Standards AnnouncementProject 2006-06 ndash Reliability CoordinationInitial Ballot Results

Now available at httpsstandardsnercnetBallotsaspx An initial ballot of the following standards and their associated implementation plans ended on March 7 2011

middot COM-001-2 ndash Communications

middot COM-002-3 ndash Communication and Coordination

middot IRO-001-2 ndash Reliability Coordination ndash Responsibilities and Authorities

middot IRO-002-2 ndash Reliability Coordination ndash Analysis Tools

middot IRO-005-4 ndash Reliability Coordination ndash Current Day Operations

middot IRO-014-2 ndash Coordination Among Reliability Coordinators

middot IRO-015-1 ndash Notifications and Information Exchange Between Reliability Coordinators

middot IRO-016-1 ndash Coordination of Real-time Activities Between Reliability Coordinators

Voting statistics are listed below and the Ballot Results Web page provides a link to the detailed results Quorum 8710Approval 4954 BackgroundThe Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related requirements applicable to theReliability Coordinator are clear measurable unique and enforceable 2) ensuring that this set of requirements is sufficient to maintainreliability of the Bulk Electric System and 3) revising the group of standards based on FERC Order 693 During the course of this project the Reliability Coordination Standards Drafting Team incorporated changes due to the work of the IROLStandards Drafting Team Two standards from the original Standards Authorization Request (PER-004 and PRC-001) were moved to otherprojects due to scope overlap In addition the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693associated with standards IRO-003-2 For more information review the project Web page

httpwwwnerccomfilezstandardsReliability_Coordination_Project_2006-6html Next StepsThe drafting team will consider all comments (those submitted with a comment form and those submitted with a ballot Once the team hasprepared its response to comments and made any changes to the standards and supporting documents they will submit the reviseddocuments for quality review prior to a successive ballot Since a non-binding poll of VRFs and VSLs was not conducted concurrent withthe initial ballot that concluded on March 7 2011 a non-binding poll will be conducted in conjunction with the successive ballot Ballot CriteriaApproval requires both (1) a quorum which is established by at least 75 of the members of the ballot pool submitting either anaffirmative vote a negative vote or an abstention and (2) a two-thirds majority of the weighted segment votes cast must be affirmative thenumber of votes cast is the sum of affirmative and negative votes excluding abstentions and non-responses Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate




6094528060 | wwwnerccom ---You are currently subscribed to nercroster as gzitonpccorgTo unsubscribe send a blank email to leave-1250569-3920898eac8c94409e17058b6e89bfa4b2626listservnerccom

From Guy V ZitoTo rsballotCc rscSubject NERC Ballot for Project 2006-06 Reliability Coordination COM-001 COM-002 IRO-001 and IRO-014Date Thursday March 03 2011 115530 AM

NPCC Members of the NERC Registered Ballot Body As FYI subsequent to the RSC recommendation sent out earlier this week toaccept and vote Affirmative on the subject project some RSC membershave indicated their intent to cast an abstention on the ballot untilsuch time as there is clarification to COM-002 (ie pre-establisheddocumentation of when 3-part communications will be employed) isincluded in the Standard These entities have expressed the opinionthat this position is a direct result of the concurrent balloting andcommenting resulting in uncertainty as to what is actually beingvotedGuy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Guy V ZitoTo rsballotCc rscSubject NERC Initial Ballot NPCC Recommendation-Project 2006-06 ― Reliability Coordination ― COM-001 COM-002

IRO-001 and IRO-014Date Wednesday March 02 2011 81933 AMImportance High

NPCC Members of the NERC Registered Ballot Body The subject Project and associated standards are currently posted at NERC and anInitial ballot is being conducted through March 7 2011 Comments are also being accepteduntil this time The RSC has reviewed the subject project and standards and has identified no showstoppersand therefore recommends an Affirmative vote to accept the standards within this project One of the more substantive non-grammatical or format related requirment that the RSC willsubmit is in relation to the issue of classifying data as part of the InterpersonalCommunications This would then require three part communication to be applied to thisdata NPCC pointed this out to the DT however the DT responded that Interpersonalcommunication implicitly was meant to refer to interpersonal or between two persons NPCC believes that perhaps a future revision will better clarify that data is not and will beincluded in the three part communication requirment

Please contact me if you have further questions Thank-you Guy V Zito Chair Regional Standards CommitteAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Ballot Window Open February 25 - March 7 2011 | Project 2006-06Date Thursday February 24 2011 42208 PM

Standards AnnouncementBallot Window Open February 25 ndash March 7 2011Project 2006-06 ndash Reliability Coordination Available Friday February 25th at httpsstandardsnercnetCurrentBallotsaspx Initial Ballot Window Open February 25th through 8 pm on March 7 2011An initial ballot for the following standards and associated implementation plans will be open from 800 am on Friday February 25through 800 pm on Monday March 7 2011 bull COM-001-2 ndash Communicationsbull COM-002-3 ndash Communication and Coordinationbull IRO-001-2 ndash Reliability Coordination ndash Responsibilities and Authoritiesbull IRO-002-2 ndash Reliability Coordination ndash Analysis Toolsbull IRO-005-4 ndash Reliability Coordination ndash Current Day Operationsbull IRO-014-2 ndash Procedures Processes or Plans to Support Coordination Between Reliability Coordinatorsbull IRO-015-1 ndash Notifications and Information Exchange Between Reliability Coordinatorsbull IRO-016-1 ndash Coordination of Real-time Activities Between Reliability Coordinators During the initial ballot window members of the ballot pool associated with this project may log in and submit their votes from thefollowing page httpsstandardsnercnetCurrentBallotsaspx BackgroundThe Reliability Coordination Standards Drafting Team was tasked with 1) ensuring that the reliability-related requirements applicable to theReliability Coordinator are clear measurable unique and enforceable 2) ensuring that this set of requirements is sufficient to maintainreliability of the Bulk Electric System and 3) revising the group of standards based on FERC Order 693 During the course of this project the Reliability Coordination Standards Drafting Team incorporated changes due to the work of the IROLStandards Drafting Team Two standards from the original Standards Authorization Request (PER-004 and PRC-001) were moved to otherprojects due to scope overlap In addition the scope of Project 2006-06 was expanded to incorporate directives from FERC Order 693associated with standards IRO-003-2 For more information review the project Web pagehttpwwwnerccomfilezstandardsReliability_Coordination_Project_2006-6html Next StepsThe comments submitted during the formal comment period and the ballot results will be posted Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate





---

You have received this email because you are a registered representative in the Registered Ballot Body

From Guy V ZitoTo rscSubject FW Standards Announcement Non-binding Polls for VSLs Now Open - October 27-November 6 2010 | Project 2007-23Date Thursday October 28 2010 114726 AM

RSC I would like to send a recommendation to accept the VSLs as written to the voting membership of NPCC As discussed at the RSCmeeting last week there were no identified issues with them as written but on a going forward basis I think we need a subgroup to helpwith their review If you are opposed to reccommending an Affirmative vote for these ballots please so indicate Thanks Guy V ZitoAssistant Vice President-StandardsNortheast Power Coordinating Council Inc1040 Avenue of the Americas 10 th FloorNew York NY 10018212-840-1070212-302-2782 fax

From Monica Benson [MonicaBensonnercnet]Sent Wednesday October 27 2010 205 PMTo monicabensonnercnetSubject Standards Announcement Non-binding Polls for VSLs Now Open - October 27-November 6 2010 | Project 2007-23

Standards AnnouncementNon-binding Polls for VSLs Now OpenOctober 27-November 6 2010

Available at httpsstandardsnercnetCurrentBallotsaspx Project 2007-23 Violation Severity LevelsThe windows for submitting opinions on each of the six sets of Violation Severity Levels (VSLs) shown below are open through 8 pmEastern on November 6 2010 VSLs - Balancing Resources and Demand (BAL) and Interchange (INT)VSLs - Interconnected Reliability Operations (IRO)VSLs ndash Nuclear (NUC) Transmission Operations (TOP) and Voltage and Reactive (VAR)VSLs ndash Communications (COM) Emergency Operations (EOP) Personnel (PER)VSLs - Facilities (FAC) and Modeling (MOD)VSLs - Protection and Control (PRC) Transmission Planning (TPL)

InstructionsMembers of the ballot pools associated with these sets of VSLs may log in and submit their opinions from the following pagehttpsstandardsnercnetCurrentBallotsaspx Next StepsThe results of the non-binding polls will be posted Project BackgroundIn its June 19 2008 VSL Order FERC directed NERC to review all VSLs (with the exception of those for which the Commission directedspecific modification) for compliance with FERCrsquos VSL Guidelines 2b 3 and 4 and submit a compliance filing either validating thecurrent Violation Severity Level assignments or proposing revision

middot Guideline 2b mdash VSLs should not use ambiguous terms such as minor or significant to describe noncompliant performance

middot Guideline 3 mdash VSLs should be consistent with the corresponding requirement (VSLs should not expand on what is in therequirement)

middot Guideline 4 mdash VSLs should be based on a single violation not on a cumulative number of violations (unless stated otherwise in therequirement)

The VSLs have been reviewed balloted and reviewed again for consistency with the FERC Guidelines The review subsequent to the lastballot identified some discrepancies and inconsistencies in the VSL assignments last balloted The VSLs that met all the Guidelines werefiled with FERC earlier this year The remaining VSLs must be filed with FERC by December 1 2010Project page httpwwwnerccomfilezstandardsVSLs_Project_2007-23html Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Project 2007-23 | Violation Severity LevelsDate Thursday January 20 2011 41127 PM

Standards AnnouncementExisting Ballot Pool Re-opened January 20-February 9 2011Comment Period Open January 20-February 18 2011Project 2007-23 ndash Violation Severity Levels Now available at httpsstandardsnercnetBallotPoolaspx The Violation Severity Level Drafting Team has made revisions to 14 sets of VSL assignments and the revisions have been posted forindustry review Included in this posting are a clean version of the affected VSLs and a redline version of the VSLs compared to thecurrent FERC-approved VSLs The documents have been posted for a 30-day concurrent formal comment period that will end at 8 pmEST on February 17 2010 The non-binding poll will take place during the last ten days of this period beginning at 8 am EST onFebruary 9 2010 Ballot Pool Open through 8 am on February 9 2011During the last set of ballots for VSLs six separate ballot pools were formed To simplify the process for balloting the current set of revisedVSLs a single ballot pool has been formed and members of the TPL VSL ballot pool (the largest of the 6 previous ballot pools) have beenpre-registered for the new VSL ballot pool Each of these preregistered members will receive an email indicating that they have been pre-registered for this new ballot pool and notice that they may drop out of the ballot pool if they donrsquot wish to participate in this new non-binding poll In addition during the first 20 days of the 30-day comment period any member of the Registered Ballot Body may join the new ballot poolto be eligible to vote in the upcoming ballot at the following page httpsstandardsnercnetBallotPoolaspx During the pre-ballot window members of the ballot pool may communicate with one another by using their ldquoballot pool list serverrdquo (Once the balloting begins ballot pool members are prohibited from using the ballot pool list servers) The list server for this ballot pool isbp-2007-23_VSL_NB_innerccom Comment Period Open through 8 pm on February 18 2011Please use this electronic form to submit comments If you experience any difficulties in using the electronic form please contact MonicaBenson at monicabensonnercnet An off-line unofficial copy of the comment form is posted on the project pagehttpwwwnerccomfilezstandardsVSLs_Project_2007-23html Next StepsA non-binding poll of the revised VSLs will take place during the last ten days of this period beginning at 8 am EST on February 9 2010 Project BackgroundIn a June 2008 order FERC directed NERC to review all VSL assignments for compliance with certain guidelines and to submit acompliance filing either justifying the current VSL assignments or proposing revisions Proposed VSLs were balloted in 2009 and a revisedproposed set of VSLs was filed with FERC on March 5 2010 In December 2010 NERC and FERC staffs met to discuss 14 sets of VSLs in need of modification In some cases changes were neededfor clarity and in other cases there was a need to modify a VSL to ensure compliance with FERCrsquos VSL Guidelines In coordination with members of the VSL DT for Project 2007-23 NERC staff made changes to ensure clarity and compliance with FERCGuidelines and these changes have been posted here for industry review Standards Development ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate For moreinformation or assistance please contact Monica Benson at monicabensonnercnet






From Monica BensonTo monicabensonnercnetSubject Standards Announcement Results of Non-Binding Poll of VSLs | Project 2007-23 Violation Severity LevelsDate Monday March 07 2011 40256 PM

Standards AnnouncementResults of Non-Binding Poll of VSLsProject 2007-23 ndash Violation Severity Levels Now available at httpwwwnerccomfilezstandardsVSLs_Project_2007-23html

A non-binding poll of proposed revisions to 14 sets of VSLs closed on February 22 2011 Of those who registered to participate 78provided an opinion 72 of those who provided an opinion indicated support for the VRFs and VSLs that were proposed The VSLs have been revised to incorporate feedback from the non-binding poll and the revised VSLs along with redlines to last postedand last approved and a comment report have been posted on the project page Next StepsThe revised VSLs will be presented to the Board of Trustees for approval Project BackgroundIn a June 2008 order FERC directed NERC to review all VSL assignments for compliance with certain guidelines and to submit acompliance filing either justifying the current VSL assignments or proposing revisions Proposed VSLs were balloted in 2009 and a revisedproposed set of VSLs was filed with FERC on March 5 2010 In December 2010 NERC and FERC staffs met to discuss 14 sets of VSLs in need of modification In some cases changes were neededfor clarity and in other cases there was a need to modify a VSL to ensure compliance with FERCrsquos VSL Guidelines In coordination with members of the VSL DT for Project 2007-23 NERC staff made changes to ensure clarity and compliance with FERCGuidelines and these changes were posted for industry review from January 20 2011 through February 22 2011 Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate













---Y

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Project 2010-13 - Relay Loadability Order 733 ModificationsDate Monday January 24 2011 60018 PM

Standards AnnouncementSuccessive Ballot and Non-binding Poll OpenProject 2010-13 ndash Relay Loadability Order 733 ModificationsJanuary 24-February 13 2011 Now available at httpsstandardsnercnetCurrentBallotsaspx Project 2010-13 Revisions to Relay Loadability for Order 733PRC-023-2 mdash Transmission Relay Loadability has been posted for a 20-day successive ballot of the proposed standard and its associatedimplementation plan through 8 pm on February 13 2011 A non-binding poll of the associated Violation Risk Factors (VRFs) andViolation Severity Levels (VSLs) will be conducted during the same time Registered Ballot Body members who joined the ballot pool to vote on the standard have already been automatically entered in a separatepool to participate in the non-binding poll for the VRFs and VSLs For ballot pool members the non-binding poll appears in the list ofcurrent ballots and is labeled accordingly InstructionsMembers of the ballot pools associated with this project may log in and submit their votes from the following pagehttpsstandardsnercnetCurrentBallotsaspx BackgroundThis standard was revised to address a set of directives in Order 733 and must be submitted to FERC by March 18 2011 To meet thisdelivery date the Standards Committee authorized use of the expedited standard development process Under the expedited standarddevelopment process the Standards Committee may alter certain steps in the standard development process to meet a regulatory deadline In this case the Standards Committee authorized the drafting team to conduct successive ballots without parallel comment periods Toallow stakeholders time to review the changes made between ballots the Standards Committee authorized an extended ballot window of 20calendar days rather than 10 calendar days Next StepsVoting results will be posted and announced after the ballot windows close Project BackgroundWhen FERC issued Order 733 approving PRC-023-1 mdashTransmission Relay Loadability it directed several changes to that standard andalso directed development of one or more new standards within specified time periods NERC filed for clarification and rehearing askingfor clarity and an extension of time to address the directives however without a response to the requests for clarification and rehearingNERC must proceed as though these requests will be deniedThe SAR for Project 2010-13 subdivides the standard-development-related directives into three phases Phase I addresses the specificdirectives from Order 733 that identified required modifications to various elements within PRC-023-1 Phase II addresses directivesassociated with development of a new standard to address generator relay loadability Phase III addresses directives associated with writingrequirements to address protective relay operations due to power swings More information on this project may be found on the project pagehttpwwwnerccomfilezstandardsSAR_Project202010-13_Order2073320Relay20Modifiationshtml Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






From Monica BensonTo monicabensonnercnetSubject Standards Announcement Project 2010-13 Relay Loadability for Order 733 - Successive Ballot ResultsDate Wednesday February 16 2011 35414 PM

Standards AnnouncementSuccessive Ballot ResultsProject 2010-13 - Relay Loadability for Order 733 Now available at httpsstandardsnercnetBallotsaspxA successive initial ballot of PRC-023-2 mdash Transmission Relay Loadability ended on February 14 2011 Voting statistics are listed belowand the Ballot Results Web page provides a link to the detailed results Ballot for Standard

middot Quorum 8395middot Approval 6571

Violation Risk Factor (VRF) and Violation Severity Level (VSL) Non-binding Poll Results

middot The poll achieved a quorum with 80 of those who registered to participate provided an opinion 65 of those who provided anopinion indicated support for the VRFs and VSLs that were proposed

Project BackgroundWhen FERC issued Order 733 approving PRC-023-1 mdash Transmission Relay Loadability it directed several changes to that standard andalso directed development of one or more new standards within specified time periods NERC filed a request for clarification andrehearing and requested additional time to address the directives however pending FERCrsquos response to the requests for clarification andadditional time NERC must progress as though these requests will be denied The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases Phase I addresses the specificdirectives from Order 733 that identified required modifications to various elements within PRC-023-1 Phase II addresses directivesassociated with development of a new standard to address generator relay loadability Phase III addresses directives associated with writingrequirements to address protective relay operations due to power swings More details may be found on the project pagehttpwwwnerccomfilezstandardsSAR_Project202010-13_Order2073320Relay20Modifiationshtml

Next StepsThe drafting team will consider all comments (those submitted with a comment form and those submitted with a ballot) and will determinewhether to make additional changes to the standard The team will post its response to comments and if the standard has only minorchanges will post the standard and conduct a 10-day recirculation ballot Ballot CriteriaApproval requires both (1) a quorum which is established by at least 75 of the members of the ballot pool submitting either anaffirmative vote a negative vote or an abstention and (2) a two-thirds majority of the weighted segment votes cast must be affirmative thenumber of votes cast is the sum of affirmative and negative votes excluding abstentions and non-responses








Senior Vice President amp General Counsel DATE March 9 2011 SUBJECT Update to Ballot Results for Reliability Standards Development Plan (Agenda

Item 1a) and Proposed PRC-023-2 Reliability Standard (Agenda Item 1d) The purpose of this memo is to update the members of the NERC Board of Trustees on

(1) The final results of the Standards Committee email ballot of the proposed Reliability Standards Development Plan 2011-2013 and

(2) The final ballot results for the proposed PRC-023-2 ndash Transmission Relay Loadability Reliability Standard which closed on March 7 2011

Agenda Item 1a Standards Committee Email Ballot of Reliability Standards Development Plan 2011-2013 The Standards Committee email ballot of the updated Reliability Standards Development Plan 2011-2013 concluded on March 3 with 17 of the 19 Standards Committee members submitting votes Fifteen Standards Committee members voted affirmatively for the revised plan There were two abstentions which meets the required 23 affirmative vote for passage A complete listing of the final Standards Committee voting record is included for reference NERC management recommends board approval of the proposed Reliability Standards Development Plan 2011-2013 Agenda Item 1d Ballot Results for PRC-023-2 A Recirculation Ballot of the PRC-023-2 Transmission Relay Loadability Reliability Standard and its associated implementation plan closed on March 7 2011 The ballot achieved a quorum of 8735 and a weighted segment approval of 6883 thereby passing the industry ballot process A Non-binding poll of the standardrsquos Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs) was also conducted and achieved a quorum of 80 and an average approval of 65 The low approval is attributed to the number of requirements that were considered ldquobinaryrdquo resulting in a single Severe VSL for five of the six requirements In proposing VRFs and VSLs the drafting team proposed VRFs and VSLs that aligned with those approved by FERC in Order 733 NERC management recommends board approval of the proposed PRC-023-2 standard its associated implementation plan and its associated VRFs and VSLs for filing with FERC

-2-

Standards Committee Email Ballot Results for RSDP 2011-13

(224 ndash February 24 2011) (32 ndash March 2 2011) (33 ndash March 3 2011)

Affirmative Negative Abstain Comments

Segment 1-2010-11 Carol A Sedewitz X (32)

Segment 1-2010-12 Jason Shaver X (33)

Segment 2-2010-11 PS (Ben) Li X (32)

Segment 2-2011-12 Patrick Brown X (32)

Segment 3-2011-12 Ronald G Parsons X (32)

Segment 4-2010-11 Allen Mosher X (33)

Segment 4-2011-12 Joseph Tarantino X (32)

Segment 5-2011-12 Michael F Gildea X (32)

Segment 6-2010-11 Alice Murdock Ireland X (32)

Segment 6-2011-12 Silvia Parada Mitchell X (33)

Segment 7-2010-11 Frank McElvain X (33)

Segment 7-2011-12 John A Anderson X (32)

Segment 8-2010-11 Jim R Stanton X (224)

Segment 8-2011-12 Michael Goggin

Segment 9-2010-11 Klaus Lambeck X (32)

Segment 9-2011-12 Diane J Barney X (32)

Segment 10-2010-11 Linda Campbell X (32)

Segment 10-2011-12 Steve Rueckert X (32)

Canada Robert Blohm








---Y

From Monica BensonTo monicabensonnercnetSubject Standards Announcement - Recirculation Ballot Window Open February 24 - March 6 2011 | Project 2010-13Date Thursday February 24 2011 32601 PM

Standards AnnouncementRecirculation Ballot Window OpenProject 2010-13 ndash Relay Loadability Order 733February 24-March 6 2011 Now available at httpsstandardsnercnetCurrentBallotsaspx Project 2010-13 ndash Relay Loadability Order 733A recirculation ballot for PRC-023-2 ndash Transmission Relay Loadability is open until 8 pm (Eastern) on March 6 2011 InstructionsMembers of the ballot pool associated with this project may log in and submit their votes from the following pagehttpsstandardsnercnetCurrentBallotsaspxIn the recirculation ballot votes are counted by exception Only members of the ballot pool may cast a ballot all ballot pool members maychange their prior votes A ballot pool member who failed to cast a ballot during the last ballot window may cast a ballot in therecirculation ballot window If a ballot pool member does not participate in the recirculation ballot that memberrsquos last vote cast in thesuccessive ballot that ended on February 14 2011 will be carried over and used to determine if there are sufficient affirmative votes for thisstandard to pass This is an extremely important ballot as NERC is responding to a set of FERC directives that require submitting modifications to PRC-023-1 by March 18 2011 We encourage all members of the ballot pool to review the revised standard and the drafting teamrsquos consideration ofthe comments submitted with the last ballot The team made the following changes following the initial ballot in support of stakeholdercomments

Modified the applicability to clarify that the transmission lines and transformers that must have protection compliant with the standardare limited to those that are part of the BES and are selected by the Planning Coordinator (Previously the applicability did not includethe phrase ldquopart of the BESrdquo)Reformatted the presentation of the effective dates so that the dates are easier to comprehend

Corrected footnote 5

Revised M4 and M5 to clarify that attestations are acceptable forms of evidence

Added another Severe VSL for R6 to cover the situation where an entity is totally noncompliant with the requirement

Changed ldquosupervisory elementsrdquo to ldquoPhase overcurrent supervisory elementsrdquo for clarity in Attachment A

The drafting team will be holding a webinar to review the modifications made to the standard on Wednesday March 2 from 1-2 pm(Eastern) The Standards Committee encourages all ballot body members to participate in this webinar Next StepsVoting results will be posted and announced after the ballot window closes This standard is scheduled to be submitted to the Board ofTrustees on March 10 2011 and filed for regulatory approval by March 18 2011 Project BackgroundWhen FERC issued Order 733 approving PRC-023-1 mdashTransmission Relay Loadability it directed several changes to that standard andalso directed development of one or more new standards within specified time periods NERC filed for clarification and rehearing asking forclarity and an extension of time to address the directives and the extension was granted but only applies to one of the directives NERC isstill required to file a revised standard that addresses several directives from Order 733 by March 18 2011The SAR for Project 2010-13 subdivides the standard-development-related directives into three phases Phase I addresses the specificdirectives from Order 733 that identified required modifications to various elements within PRC-023-1 Phase II addresses directivesassociated with development of a new standard to address generator relay loadabilty Phase III addresses directives associated with writingrequirements to address protective relay operations due to power swings Further details are available on the project pagehttpwwwnerccomfilezstandardsSAR_Project202010-13_Order2073320Relay20Modifiationshtml Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERC

standards development process depends on stakeholder participation We extend our thanks to all those who participate






From Monica BensonTo monicabensonnercnetSubject Standards Announcement Project 2010-13 ndash Relay Loadability Order | Recirculation Ballot ResultsDate Tuesday March 08 2011 25433 PM

Standards AnnouncementProject 2010-13 ndash Relay Loadability OrderRecirculation Ballot Results Now available at httpsstandardsnercnetBallotsaspx Ballot Results for Revisions to PRC-023A recirculation ballot on revisions to PRC-023 Transmission Relay Loadability concluded on March 7 2011 The revised standard PRC-023-2 was approved by the ballot pool Voting statistics are listed below and the Ballot Results Web page provides a link to the detailed resultsQuorum 8735Approval 6883 Next StepsPRC-023-2 will be presented to the NERC Board of Trustees for adoption and filed with regulatory authorities

BackgroundAs the ERO NERC must address all directives in Orders issued by FERC On March 18 2010 FERC issued Order No 733 whichapproved Reliability Standard PRC-023-1 ndash Transmission Relay Loadability and also directed NERC as the Electric ReliabilityOrganization (ldquoEROrdquo) to develop certain modifications to the PRC-023-1 standard through its Reliability Standards development processto be completed and filed with the Commission by March 18 2011 Attachment 1 to the SAR contains the directives and associateddeadlines The Order also directed development of two new Reliability Standards to address issues related to generator relay loadability andthe operation of protective relays due to power swings The standards-related directives in Order 733 are aimed at closing some reliability-related gaps in the scope of PRC-023-1

The SARrsquos scope includes three standard development phases to address the standards-related directives in Order No 733 directives PhaseI is focused on making the specific modifications to PRC-023-1 that were identified in the order Phase II is focused on developing a newstandard to address generator relay loadability and Phase III is focused on developing requirements that address protective relay operationsdue to power swings

Further details are available on the project page httpwwwnerccomfilezstandardsSAR_Project202010-13_Order2073320Relay20Modifiationshtml Standards ProcessThe Standard Processes Manual contains all the procedures governing the standards development process The success of the NERCstandards development process depends on stakeholder participation We extend our thanks to all those who participate






Unofficial Comment Form for Standards Committeersquos Project Prioritization Reference Document and Tool Please do not use this form to submit comments on the draft standard prioritization tool and associated reference document Please use the electronic comment form to submit your comments Comments must be submitted by February 10 2011 If you have questions please contact Maureen Long at maureeenlongnercnet or by telephone at 813-468-5998


The Standards Committee has posted a draft standard project prioritization tool and reference document (Standards Committee Process for Standard Project Identification Prioritization and Monitoring) proposed for use in prioritizing standard projects Comments will be accepted through February 10 2011

During the past few years the Standards Committee has been presented with more proposals for developing new or revised projects than can be accomplished at one time The project prioritization tool is an excel spreadsheet that provides a transparent method of identifying the reliability-related benefits associated with each standard development project The tool provides the flexibility to accommodate new projects and to adjust project priorities and completion schedules in response to changing conditions and will be used to assign a priority to each standard project proposed for development


You are encouraged to read the reference document and then review the tool and the ratings assigned to each of the proposed projects

We ask that you provide comments on the tool and then comments on the initial set of ratings If you disagree with the rating assigned to a specific project please identify why you believe the rating is incorrect and identify what rating you believe is more appropriate Please be as specific as possible to help the Standards Committee in making adjustments to the ratings already assigned For example if you believe that the proposed project will fill a reliability gap that is not properly rated identify the reliability gap that is addressed in the project



Standards Committee Process for Standard Project Identification Prioritization and Monitoring 1 Please provide any comments you have on the draft reference document

Comments Oftentimes prioritization of projects relies on experience engineering and technical judgment This tool and reference document provide useful and helpful guidance to the Project Prioritization activity bringing objectivity to what can be a very subjective process Refer also to question 8 below

Project Prioritization Tool

2 Do you agree with the range of questions (column headings) in the tool

Yes

No

Comments

3 Do you agree that the range (0-100) for the red and orange columns in the tool

Yes

No

Comments The range in Red Column ldquogrdquo is 0 to 50 Otherwise agree

4 Do you agree that the range (0-50) for four of the yellow columns with the column identifying the investment already made in the project rated with a possible rating of 0-100

Yes

No

Comments 5 Do you agree that the range (0-100) for the blue column in the tool

Yes

No

Comments 6 What factors do you believe the Standards Committee should consider in the ldquoOtherrdquo

column

Yes

No

Comments The ldquoExplanationrdquo column ldquoprdquo allows room for explanations of the lsquoOtherrdquo column

Proposed Ratings for Projects Included in the Reliability Standard Development Plan

7 Please review the ratings assigned to each of the individual projects If you feel that any of the draft ratings are inaccurate please identify the project number and the specific rating that you believe is inaccurate Please be specific in identifying what you believe is the correct rating and provide a justification for that proposed rating

Comments

8 Please provide any other comments you feel would be beneficial to the Standards Committee in making improvements to the reference document and project prioritization tool

Comments In NERCrsquos 2011 Plan there are 17 Priority Standards identified This exceeds the resources available quoting from p 5 Section 3 ldquoRecent Standards Committee and NERC staff experience generally supports the conclusion that NERC and the industry can manage the development of no more than ten to twelve standards projects under active development at any one time hellip our informed judgment is that attempts to develop more than ten or twelve projects during the same period will result in an actual loss of throughput andor a reduction in standards qualityrdquo There are no explanations supporting the scoring values Why is one criteria worth 10 while another 25 or 100 Weighted Criteria-Based Scoring Systems for Project Management under Resource Constraints are widely used to select and prioritize projects Generally the projected sum-of-the-projects results are indicative of some bottom-line measure like impact on profits Here the bottom-line impact on reliability is only indirectly indicated through the very qualitative unsupported values assigned to the various criteriameasures eg 10 25 or 100 Shouldnrsquot some more quantitative Reliability measure be used for scoring such as some threshold improvement in LOLP or a minimum benefitcost ratio eg 121 Why are certain cells highlighted yellow in the body of the Prioritization Tool

















Page 2 of 7


Yes

No

1 Comments





Yes

No

2 Comments




Yes

No

Comments




Yes

No

Comments


Page 3 of 7


Bias Setting



Yes

No

Comments





Yes

No

Comments



Yes

No

Comments


Yes

No

Comments


Page 4 of 7


Yes

No

Comments



Yes

No

Comments


Yes

No

Comments


Yes

No

Comments


Yes

No

Comments


Yes

No


Page 5 of 7

Comments



Comments





Page 6 of 7






Page 7 of 7



















Page 2 of 7


Yes

No

1 Comments





Yes

No

2 Comments




Yes

No

Comments




Yes

No

Comments


Page 3 of 7


Bias Setting



Yes

No

Comments





Yes

No

Comments



Yes

No

Comments


Yes

No

Comments


Page 4 of 7


Yes

No

Comments



Yes

No

Comments


Yes

No

Comments


Yes

No

Comments


Yes

No

Comments


Yes

No


Page 5 of 7

Comments



Comments





Page 6 of 7






Page 7 of 7





Official Comment Form for Project 2007-23 mdash Violation Severity Levels Please DO NOT use this form Please use the electronic comment form to submit comments on the proposed revisions to 14 sets of VSLs Comments must be submitted by February 18 2011 If you have questions please contact Mallory Huggins at malloryhugginsnercnet or by telephone at 609-619-1629



Name

Organization

Telephone

E-mail NERC Region Registered Ballot Body Segment

ERCOT FRCC MRO NPCC RFC SERC SPP WECC NA ndash Not Applicable

1 mdash Transmission Owners 2 mdash RTOs and ISOs 3 mdash Load-serving Entities 4 mdash Transmission-dependent Utilities 5 mdash Electric Generators

6 mdash Electricity Brokers Aggregators and Marketers 7 mdash Large Electricity End Users 8 mdash Small Electricity End Users 9 mdash Federal State Provincial Regulatory or other Government Entities 10 mdash Regional Reliability Organizations and Regional Entities


Page 2 of 6


Group Name Regional Standards Committee of the NPCC

Lead Contact

Contact Organization

Contact Segment

Contact Telephone

Contact E-mail If more than one Region or Segment applies indicate the best fit for the purpose of these comments Regional

acronyms and segment numbers are shown on prior page Additional Member Name Additional Member Organization Region Segment


Page 3 of 6

Background Information In its June 19 2008 VSL Order FERC directed NERC to review all Violation Severity Level (VSL) assignments ndash with the exception of those for which the Commission directed specific modification ndash for compliance with the following Guidelines 2b 3 and 4 and submit a compliance filing either validating the current VSL assignments or proposing revision

bull Guideline 2b mdash VSLs should not use ambiguous terms such as minor or significant to describe noncompliant performance

bull Guideline 3 mdash VSLs should be consistent with the corresponding requirement (VSLs should not expand on what is in the requirement)

bull Guideline 4 mdash VSLs should be based on a single violation not on a cumulative number of violations (unless stated otherwise in the requirement)

The VSL Drafting Team (VSL DT) posted the proposed VSLs1

for stakeholder comment from April 1-30 2009 The drafting team produced a redline version of each set of VSLs to show stakeholders the original set of VSLs that was balloted in 2008 the changes proposed by the VSL DT in April 2009 and additional changes made based on stakeholder comments in June 2009

The modifications made during this process were filed with FERC on March 5 2010 In December 2010 NERC and FERC staffs met to discuss 14 sets of VSLs in need of modification In some cases changes were needed for clarity and in other cases there was a need to modify a VSL to ensure compliance with FERCrsquos VSL Guidelines In coordination with members of the VSL DT for Project 2007-23 NERC staff made changes to ensure clarity and compliance with FERC Guidelines and these changes have been posted here for industry review A ballot pool from the last VSL comment period and nonbinding poll which took place from September 27 2010 through November 6 2010 has been cloned to create the ballot pool for this concurrent comment period and nonbinding poll Included in this posting are a clean version of the affected VSLs and a redline version of the VSLs compared to the current FERC-approved VSLs The documents have been posted for a 30-day concurrent formal comment and nonbinding poll period that will end at 8 pm EST on February 18 2010 The nonbinding poll will take place during the last ten days of this period beginning at 8 am EST on February 9 2010 NERC staff in coordination with the VSL Drafting Team will consider and respond to comments and make conforming changes where necessary The revised VSLs will be presented to the Board of Trustees for approval and then will be filed with applicable regulatory authorities Project page httpwwwnerccomfilezstandardsVSLs_Project_2007-23html

1 BAL-001 through BAL-006 CIP-001 COM-001 and COM-002 FAC-001 FAC-002 FAC-003 FAC-008 FAC-009 and FAC-013 INT-001 INT-003 through INT-010 IRO-001 through IRO-006 and IRO-014 through IRO-016 MOD-006 MOD-007 MOD-010 MOD-012 and MOD-016 through MOD-021 PER-001 through PER-004 NUC-001 PRC-001 PRC-004 PRC-005 PRC-007 through PRC-011 PRC-015 through PRC-018 PRC-021 and PRC-022 TOP-001 through TOP-008 TPL-001 through TPL-004 VAR-001 and VAR-002





1 Do you agree with the proposed VSL(s) modifications for BAL-003-01b R1

If not please offer your suggested alternative language

Yes

No

Comments


Yes

No

Comments In the Severe VSL insert ldquotelecommunication facilitiesrdquo after ldquovitalrdquo to improve sentence clarity The High and Severe VSLs need to be clarified We understand ldquoemergency telecommunications facilities and equipment not used for routine communicationsrdquo to be a subset of ldquovital telecommunications facilitiesrdquo However as written the VSLs seem to treat these ldquoemergency telecommunications facilitiesrdquo as separate from the ldquovital telecommunications facilitiesrdquo If these emergency telecommunications facilities and equipment ARE considered vital we suggest removing the High VSL and in the Severe VSL replacing ldquoandrdquo before ldquoemergency telecommunications facilitiesrdquo with ldquoincludingrdquo


Yes

No

Comments Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement Suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of the main requirement For the High VSL replace ldquoallrdquo with ldquoat least onerdquo and make consequential changes to avoid a problem if some but not all entities were notified The text would read ldquofailed to notify at least one other potentially affected Balancing Authority or Transmission Operatorrdquo

4 Do you agree with the proposed VSL(s) modifications for FAC-003-1

R1221 If not please offer your suggested alternative language

Yes

No

Comments Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement Suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of the


Page 5 of 6

main requirement Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement Suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of the main requirement



Yes

No

Comments For the Severe VSL ldquoorrdquo should be replaced by ldquoORrdquo to make it clear that what follows is a second part to the VSL and ldquocontingencyrdquo (following ldquoorrdquo) should be capitalized



Yes

No

Comments For the Severe VSL replace ldquoreducingrdquo with ldquoreduction ofrdquo For the Severe VSL replace ldquoreducingrdquo with ldquoreduction ofrdquo



Yes

No

Comments For the Lower VSL we suggest replacing ldquoprovided after the required time (but not more than one hour after the required time)rdquo with ldquoprovided up to one hour after the required timerdquo For the Moderate VSL we suggest the sentence structure ldquomore than one hour and up to (and including) two hours after the required timerdquo A similar structure is suggested for the High VSL



Yes

No

Comments For consistency in language across all VSLs of this requirement ldquoinformationrdquo in the Moderate High and Severe VSLs should be changed to ldquoresultsrdquo We also suggest a sentence structure for the Lower Moderate and High VSLs similar to what was proposed in our response to Q7



Yes

No

Comments


Page 6 of 6


Yes

No

Comments


Yes

No

Comments Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement We therefore suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of Requirement R32 into a set of VSLs for the main requirement Also for consistency with the other VSLs we suggest inserting ldquoeitherrdquo after ldquowithrdquo for the Severe VSL



Yes

No

Comments Consistent with NERCrsquos VSL Guidelines applied in the previous posting the VSL of the sub-requirement should be incorporated into the VSL of the main requirement We therefore suggest the stated VSLs be ldquoOR-edrdquo with the corresponding VLSs of the main requirement



Yes

No

Comments For the High VSL replace ldquowasrdquo with ldquowererdquo


Yes

No

Comments



Comment Form for Reliability Coordination ndash Project 2006-06 Please DO NOT use this form Please use the electronic comment form to submit comments on the proposed revisions to COM-001-2 IRO-001-2 IRO-002-2 and IRO-005-4 Comments must be submitted by March 7 2011 If you have questions please contact Stephen Crutchfield at stephencrutchfieldnercnet or by telephone at 609-651-9455



Name

Organization

Telephone

E-mail

NERC Region (check all Regions in which your company operates)

Registered Ballot Body Segment (check all industry segments in which your company is registered)

ERCOT

FRCC

MRO

NPCC

RFC

SERC

SPP

WECC

NA ndash Not Applicable

1 mdash Transmission Owners

2 mdash RTOs and ISOs

3 mdash Load-serving Entities

4 mdash Transmission-dependent Utilities

5 mdash Electric Generators

6 mdash Electricity Brokers Aggregators and Marketers

7 mdash Large Electricity End Users

8 mdash Small Electricity End Users

9 mdash Federal State Provincial Regulatory or other Government Entities

10 mdash Regional Reliability Organizations and Regional Entities


Page 2 of 7


Group Name IRC Standards Review Committee

Lead Contact Albert DiCaprio

Contact Organization PJM

Contact Segment ISO amp RTO

Contact Telephone 610 ndash 666 ndash 8854

Contact E-mail dicaprampjmcom

Additional Member Name Additional Member Organization

Region Segment

If more than one Region or Segment applies please list all that apply Regional acronyms and segment numbers are shown on prior page


Page 3 of 7




Alternative Interpersonal Communication Any method Interpersonal Communication that is able to serve as a substitute for and is redundant to normal Interpersonal Communication and does not utilize the same infrastructure (medium) as normal Interpersonal Communications used for day-to-day operation

The RCSDT believes that these are better more concise definitions The RCSDT reviewed the Interpersonal Communications capability requirements (COM-001) and determined that there were implicit requirements within the requirements For example the requirement to identify an Alternative Interpersonal Communications capability implied that an entity had an interpersonal Communication capability Rather than leave these requirements implicit the RCSDT explicitly delineated by entity the requirements for Interpersonal Communications capability and Alternative Interpersonal Communications capability These explicit requirements are R1 through R8

Minor clarifying revisions were made to R2 and R3 of COM-002-2 and the words ldquoactual or expectedrdquo were removed from the proposed definition of Adverse Reliability Impacts The RCSDT believes that these conforming revisions indicate that consensus has been achieved with respect to COM-002-2

The RCSDT also is seeking stakeholder input with regard to a FERC Order 693 directive to consider Xcelrsquos comments relating to COM-002 The comment is as follows

Paragraph 523 ldquoNERC should consider Xcelrsquos suggestion that the entity taking operating actions should not be held responsible for the delays caused by the reliability coordinatorrsquos assessment and approval We note that the operating entity has the authority to take emergency actions to protect its system that may circumvent or preempt the reliability coordinatorrsquos approval process under TOP-001-1 Requirement R3 in cases of personnel safety potential equipment failure or environmental needsrdquo

The RCSDT agrees with FERC that an entity has the right and obligation to take action to prevent or mitigate emergencies etc Footnote 226 of Order 693 discusses TOP-001 requirements

Footnote 226 TOP-001-1 R1 states in part ldquoEach transmission operator shall have the responsibility and clear decision-making authority to take whatever actions are needed to ensure the reliability of its area helliprdquo and R2 states in part ldquoEach transmission operator shall take immediate actions to alleviate operating emergencies helliprdquo

The RCSDT believes that these requirements obviate the need to develop additional requirements to address Xcelrsquos comment

The RCSDT also met with FERC staff regarding the requirements contained in the proposed IRO-001 A suggestion was made to move some of the proposed requirements to IRO-002


Page 4 of 7

and IRO-005 as these requirements did not meet the purpose of the proposed IRO-001 standard The proposed IRO-001 standard is the ldquoumbrellardquo standard that established Reliability Coordinators and their authority The requirements that were subsequently re-inserted into IRO-002 and IRO-005 pertained to analysis tool outages and Reliability Coordinator notifications respectively

The drafting team also re-introduced into IRO-001 the requirement for regions to establish Reliability Coordinators The requirement is now applicable to Regional Entities and calls for the RE to ldquoensure at least one or more Reliability Coordinators is certified to continuously assess transmission reliability and coordinate emergency operations among the operating entities within the region and across the regional boundariesrdquo This requirement was originally proposed to be retired however after discussion with NERC legal staff the RCSDT proposed to retain the requirement and revise it as shown in the draft



1 Do you agree with COM-001 requirements for Interpersonal Communications capability and Alternative Interpersonal Communications capability (R1-R8) If not please explain in the comment area below

Yes

No Comments It was expressed in the last posting that the definition of Interpersonal Communications might inadvertently include data The SDT responded that it does not by referring to Interpersonal in the wording of the definition The word being defined shouldnrsquot be in the definition However incorporating ldquoallows two or more individuals to helliprdquo is an option that may solve this problem The next posting should clarify this This standard does not comport with the informational filing that NERC submitted to FERC on August 10 2009 regarding its discontinued use of sub-requirements in standards development activities The sub-requirements should be modified into bulleted lists Consider striking ldquoto exchange Interconnection and operating informationrdquo in R1 R3 R5 R7 and R8 It is redundant to the use of Interpersonal Communications ldquoto interact consult or exchange informationrdquo in the definition Consider striking ldquoto exchange Interconnection and operating informationrdquo in R2 R4 R6 It is redundant to the use of Alternative Interpersonal Communications which uses Interpersonal Communications in its definition Interpersonal Communications includes ldquoto interact consult or exchange informationrdquo in its definition For R2 why is Interchange Coordinator excluded It is included in the Requirement R1 which deals with the Interpersonal Communications Communications would need to be maintained with the Interchange Coordinator in the event of a failure of the Interpersonal Communications For R3 affected neighboring Transmission Operators should be included For R4 and R6 the sub-requirement list is different from the associated Interpersonal Communications requirements R3 and R5 respectively These should be duplicate The sub-requirement list for R4 should match R3 and the sub-requirement list for R6 should match R5 In the event of a failure of the Interpersonal


Page 5 of 7

Communications the Transmission Operator and Balancing Authority both would need to maintain communications to the same entities as in the requirement to have Interpersonal Communications The sub-requirements should be bulleted lists For R5 why are neighboring Balancing Authorities not included Additionally R5 should only read Contact with Interchange Coordinator within the same Interconnection They need to be able to contact one another to identify discrepancies in scheduling and sources of meter error that could lead to deviations in ACE Should R2 R4 and R6 be constructed parallel to R1 R3 and R5 In R1 R3 and R5 the requirement is ldquoshall haverdquo while in R2 R4 and R6 the requirement is ldquoshall designaterdquo Since one is for the Interpersonal Communications and the other is for the Alternative Interpersonal Communications the same wording should be used R22 and R12 should not be limited to Reliability Coordinators in the same Interconnection only Modify ldquowithin the same Interconnectionrdquo to ldquowithin the same Interconnection and as appropriate between a-synchronously connected RCs which are not precluded by law from scheduling interchange energy (for schedule changes curtailments etc)rdquo since reliability coordination may be required among the RCs on both sides of an Interconnection boundary The VSLs for R1 through R8 should be expanded to include multiple levels based on the number of entities that the functional entity does not have Interpersonal Communications or Alternative Interpersonal Communications with FERC specified their general preference for gradated in paragraph 27 of their June 19 2008 order on VSLs The second half of the Severe VSL for R9 is almost a duplicate of the Lower VSL There are some small changes in the wording but both situations deal with the case where there is a problem that has been identified with the Interpersonal Communications system and it takes more than two hours to initiate repair

2 The RCSDT believes that the requirements of TOP-001-1 obviate the need to develop additional requirements to address Xcelrsquos comment Do you agree If not please explain in the comment area below

Yes

No Comments If the requirement were going to remain but the Project 2007-03 Real-Time Operations SDT proposed to retire that requirement during their last posting There needs to be better coordination with that SDT

3 Do you agree with the revision to IRO-001 R1 for certifying Reliability Coordinators If not please explain in the comment area below

Yes

No Comments The language ldquoto continuously assess transmission reliabilityrdquo should be changed to ldquoto continuously assess Bulk Electric System reliabilityrdquo to reflect what the enforceability of the standards are meant to be The requirement on the ERO should also be expanded similar to BAL-005-01b R1 to ensure that all operating entities and the entire BES are covered under a Reliability Coordinator In R2 should ldquoofrdquo be ldquotordquo Reliability Directives are issued to TOPs BA etc The VSL for R1 is not consistent with the requirement The requirement applies to the ERO but the VSL applies to the Regional Entity


Page 6 of 7

4 Do you agree with moving two requirements from IRO-001 back to IRO-002 relating to Analysis Tool outages If not please explain in the comment area below

Yes

No

Comments

5 Do you agree with moving two requirements from IRO-001 back to IRO-005 relating to Reliability Coordinator notifications If not please explain in the comment area below

Yes

No Comments R1 states ldquoWhen the results of an Operational Planning Analysis or Real-time Assessment indicate an expected or actual condition with Adverse Reliability Impacts within its Reliability Coordinator Area each Reliability Coordinator shall notify issue an alert to all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Areardquo The word ldquonotifyrdquo should be stuck

6 Do you have any other comment not expressed in questions above for the RC

SDT

Comments The SDT did not address all concerns with COM-002-3 from the last posting For entities registered as multiple functions the combination of the definition of Reliability Directive and Requirement R1 could be confused to require a company to issue directives to itself There are several organizations registered as a Reliability Coordinator Transmission Operator and Balancing Authority In these companies it is not uncommon for those responsibilities to be distributed across multiple desks Thus for certain situations a single System Operator may actually be the Reliability Coordinator and the Transmission Operator In other situations the System Operator serving the Reliability Coordinator function may be adjacent to the System Operator serving as the Transmission Operator or Balancing Authority It should never be necessary for these System Operators to issue Reliability Directives to themselves in the first example or to their co-worker in the second example to demonstrate compliance to NERC standards How the entity coordinates its actions among its Reliability Coordinator Balancing Authority and Transmission Operator roles is a corporate governance issue that should not be confused or complicated by the NERC standards Thus standards should be made clear that the Reliability Directive is directed to another company In place of requiring an operator in real-time to state ldquothis is a Reliability Directiverdquo there should be an allowance for an entity to develop procedures indicating in advance their expectations for three-part communications to their sub-operating entities Therefore we suggest modifying R1 to be ldquoWhen a Reliability Coordinator Transmission Operator or Balancing Authority requires actions to be executed as a Reliability Directive the Reliability Coordinator Transmission Operator or Balancing Authority shall identify the action either verbally when the communication is issued or in advance through documented procedures as a Reliability Directive to the recipient [Violation Risk Factor High][Time Horizon Real-Time]rdquo Also the definition of Emergency as currently cited in these draft Standards and included in the existing NERC Glossary should be modified to include the NERC Glossary term Adverse Reliability Impact to make the Standards more crisp clear and enforceable Because the Project 2007-03 Real-Time Operations SDT proposed to utilize the definition of Adverse Reliability Impact in TOP-001-2 R5 during the last posting the change to the definition should be coordinated with that team


Page 7 of 7

There is a text box in IRO-005-4 that indicates this standard will be retired Yet there still remain requirements in the standard and various other associated documentation that indicates requirements are being move to this standard Delete the text box Strike IRO-014-2 Part 17 There is no need to have a weekly conference to discuss every Operating Procedure Operating Process and Operating Plan As this requirement is written a conference call would be necessary for each Furthermore IRO-014-2 R4 already includes a requirement to have weekly conference calls that should suffice IRO-014-2 R2 seems to recognize that these Operating Procedures Processes and Plans likely will not need to be discussed weekly as it only requires an annual update Requirement R2 in IRO-001 contains the words ldquowhich could include issuing Reliability Directivesrdquo but Reliability Directives are not referenced anywhere else in the standard This inclusion seems unnecessary since without it R2 already requires that the RC take actions or direct actions by others to prevent identified events or mitigate the magnitude or duration of actual events that result in Adverse Reliability Impacts Whether or not a Reliability Directive is issued is irrelevant in this requirement These words should be removed Note that COM-002 already stipulates the requirement for 3-part communication when a Reliability Directive is issued The inclusion of ldquowhich could include issuing Reliability Directivesrdquo in IRO-001 is unnecessary

From Lee R PedowiczTo cancommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject FW Draft CAN-0015 Unavailability of NERC ToolsDate Friday February 18 2011 51911 PM


middot A CAN should not impose additional requirements middot It is important that a requirement is met not how you meet it middot If it is necessary to use a NERC tool to meet a requirement then it should be done that

way middot If changes are required then the NERC Standards Development process should be usedmiddot A CAN should only be used as a guideline


From Lee R PedowiczTo cancommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject Draft CAN-0016 CIP-001-1 R1 - Applicability to Non-BESDate Friday February 18 2011 51753 PM


middot Having procedures and training to deal with sabotage to both BES and non-BES facilities isgood utility practice and should be encouraged However NERC and the Regions have nolegal authority to enforce the applicability of the reliability standards to non-Bulk ElectricSystem elements

middot Should not establish requirements for reporting on non-BES elements This is not the rightvenue for establish that requirement

middot CANs are for guidance not for establishing requirements on non-Bulk Electric Systemelements


From Lee R PedowiczTo cancommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject Draft CAN-0017 CIP-007 R5 System Access and Password ControlsDate Friday March 04 2011 81200 AMAttachments LP--Draft comments CAN-0017--3-4-11doc

Good morning Following are NPCCrsquos contributors to these comments and the comments on the subjectdocument (I also attached a Word version)

Member Organization Region SegmentSelection

1 Adamson Alan New York State Reliability Council LLC NPCC 10

2 Guy Zito Northeast Power Coordinating Council NPCC 10

3 Campoli Gregory New York Independent System Operator NPCC 2

4 Chong Kurtis Independent Electricity System Operator NPCC 2

5 Clermont Sylvain Hydro-Quebec TransEnergie NPCC 1

6 Dackow Bohdan M US Power Generating Company (USPG) NPCC ---

7 De Graffenried Chris Consolidated Edison Co of New York Inc NPCC 1

8 Dunbar Gerry NPCC NPCC 10

9 Evans-Mongeon Brian D Utility Services NPCC 8

10 Garton Mike Dominion Resources Services Inc NPCC 5

11 Gooder Brian L Ontario Power Generation Incorporated NPCC 5

12 Goodman Kathleen ISO - New England NPCC 2

13 Haswell Chantel FPL Group Inc NPCC 5

14 Kiguel David Hydro One Networks Inc NPCC 1

15 Lombardi Michael R Northeast Utilities NPCC 1

16 MacDonald Randy New Brunswick Power Transmission NPCC 1

17 Metruck Bruce New York Power Authority NPCC 6

18 Pedowicz Lee NPCC NPCC 10

19 Pellegrini Robert The United Illuminating Company NPCC 1

20 Saksena Saurabh National Grid NPCC 1

21 Schiavone Michael National Grid NPCC 1

Comments--NERC Compliance Application Notice mdash DRAFT

(for CAN-0017)

NPCC comments on Compliance Application Notice - Draft

middot On the posted Compliance Application Notice ndash Draft there is no identification of it as CAN-0017

middot The way the information in the CAN is organized is confusing A discussion of R5 R51 and R52 appears on p 2 and again on p 4 The discussion for R53 is similarly broken up

middot The CAN does not clarify the content of R53 regarding passwords

middot NPCCrsquos participating members that review and track the CANs through the process remain concerned that sufficient industry review is not undertaken due to the location of the posted materials on the NERC website and difficulty in accessing those materials

middot Concern exists with the process in general that it is not FERC nor industry approved does not reside in the ROPs and also does not result in an attachment to the standard nor are there any requirements for refiling with the FERC and Provincial authorities as does a formal interpretation to keep record of the matter

middot Comments received from industry are not made known through posting

middot The way the CAN is written is overly prescriptive and does not allow acceptable deviations from what is written in the Standard and by so doing are encouraging possible reductions in cyber security The ERO is moving to results based standards and specific objectives should be the only critical concern not how the objective is achieved The CAN should provide clarity on situations where the Entity exceeds the Requirementobjective via other means such as two factor authentication or one time passwords The CAN should not be necessitating the need for more TFEs in these situations The Entityrsquos other choice is to be strictly compliant by reducing cyber-security by implementing the minimal expectations as specified in the Standard This result is not desirable

middot On page 2 under Background ndash Password Controls states

ldquoConsequently registered entities under currently owned equipment software and security password schemes may not have the ability to ensure compliance with the standard via a fully compliant technical solution or the registered entity may not find it operationally feasible to comply under a technical solutionrdquo

middot The question of having a procedural control accepted when a technical solution is not available remains unanswered


ldquoNERC and the Regional Entities have determined that the ldquoandrdquo in R5 reflects that both technical and procedural controls are required throughout the sub-requirements R51 and R52 but both are not required for each of the actions required by R51 and R52 Therefore a registered entity must have implemented the appropriate control ndash either a technical or procedural control ndash as required for each actionrdquo

middot The issue of the acceptability of a procedural control needs to be addressed The above is contradictory and adds confusion Resolution of the procedural control ambiguity would resolve the contradiction and should be done during the next revision of the Cyber Standards as this will potentially result in a change to the Requirement


ldquoIf the softwarersquos technical solution only partially meets the requirements of the standard but the equipment has the capability to fulfill all requirements of the standard by also implementing a procedural solution for the remaining requirements the registered entity to be compliant with the standard should implement a procedural solution for any requirements that the technical solution cannot fulfill3rdquo

middot NPCC participating members do not agree with ldquofootnote 3rdquo which states the use of a procedural control when technical controls cannot enforce a requirement requires a TFE

middot Enforcement via procedural controls should be acceptable


ldquoIf a registered entity has equipment for which a partially or fully compliant technical solution is available4rdquo

middot ldquoFootnote 4rdquo introduces the term ldquoreasonablerdquo Reasonable is not a term that is objectively auditable and has in the past been rejected by FERC


ldquoAlthough the standard does not outline what constitutes a good procedural solution a sufficient procedural solution would include a compliant policy statement personnel training and other compensating measures such as requiring longer passwords restricting electronic access and a more frequent password change cycle6rdquo

middot The Standard does not state what constitutes a good procedural solution Acceptability should be determined through the approval of a TFE not by promulgating a CAN



middot NPCC participating members suggest that this is the only situation that requires a TFE Equipment that cannot meet the Requirement is different from equipment not technically enforcing the Requirement


ldquoWhere a registered entityrsquos technical solution does not have the ability to fully meet the requirements of R53 the registered entity must have an approved TFE8helliprdquo

middot This appears to contradict the previous section which indicated that a TFE was necessary if a technical solution did not enforce the Requirement and there was no procedural solution

middot This contradicts Compliance application Password Controls - R53-3 on p 3 of the CAN that states ldquoIf a registered entity has equipment for which neither a technical solution nor a procedural solution can be implemented a registered entity in order to be compliant with the standard must obtain an approved TFE7rdquo This section is saying that a TFE is needed if only a technical solution is lacking


ldquoattestations from persons responsible for implementing andor complying with the procedural solutionrdquo


Page 3 of 4 322011

22 Sipperly Wayne New York Power Authority NPCC 5

23 Weaver Donald New Brunswick System Operator NPCC 2

24 Wu Ben Orange and Rockland Utilities NPCC 1

25 Yost Peter Consolidated Edison Co of New York Inc NPCC 3

Comments--NERC Compliance Application Notice mdash DRAFT(for CAN-0017)

NPCC comments on Compliance Application Notice - Draft middot On the posted Compliance Application Notice ndash Draft there is no identification of it as

CAN-0017middot The way the information in the CAN is organized is confusing A discussion of R5 R51

and R52 appears on p 2 and again on p 4 The discussion for R53 is similarly brokenup

middot The CAN does not clarify the content of R53 regarding passwordsmiddot NPCCrsquos participating members that review and track the CANs through the process

remain concerned that sufficient industry review is not undertaken due to the locationof the posted materials on the NERC website and difficulty in accessing those materials

middot Concern exists with the process in general that it is not FERC nor industry approveddoes not reside in the ROPs and also does not result in an attachment to the standardnor are there any requirements for refiling with the FERC and Provincial authorities asdoes a formal interpretation to keep record of the matter

middot Comments received from industry are not made known through postingmiddot The way the CAN is written is overly prescriptive and does not allow acceptable

deviations from what is written in the Standard and by so doing are encouragingpossible reductions in cyber security The ERO is moving to results based standards andspecific objectives should be the only critical concern not how the objective isachieved The CAN should provide clarity on situations where the Entity exceeds theRequirementobjective via other means such as two factor authentication or one timepasswords The CAN should not be necessitating the need for more TFEs in thesesituations The Entityrsquos other choice is to be strictly compliant by reducing cyber-security by implementing the minimal expectations as specified in the Standard Thisresult is not desirable

middot On page 2 under Background ndash Password Controls statesldquoConsequently registered entities under currently owned equipment software

and security password schemes may not have the ability to ensure compliancewith the standard via a fully compliant technical solution or the registered entitymay not find it operationally feasible to comply under a technical solutionrdquo

middot The question of having a procedural control accepted when a technical solution is

not available remains unanswered


ldquoNERC and the Regional Entities have determined that the ldquoandrdquo in R5 reflects thatboth technical and procedural controls are required throughout the sub-requirements R51 and R52 but both are not required for each of the actionsrequired by R51 and R52 Therefore a registered entity must have implementedthe appropriate control ndash either a technical or procedural control ndash as required foreach actionrdquo

middot The issue of the acceptability of a procedural control needs to be addressed Theabove is contradictory and adds confusion Resolution of the procedural controlambiguity would resolve the contradiction and should be done during the nextrevision of the Cyber Standards as this will potentially result in a change to theRequirement


ldquoIf the softwarersquos technical solution only partially meets the requirements of thestandard but the equipment has the capability to fulfill all requirements of thestandard by also implementing a procedural solution for the remainingrequirements the registered entity to be compliant with the standard shouldimplement a procedural solution for any requirements that the technical solution

cannot fulfill3rdquo

middot NPCC participating members do not agree with ldquofootnote 3rdquo which states the useof a procedural control when technical controls cannot enforce a requirementrequires a TFE

middot Enforcement via procedural controls should be acceptable middot On page 3 under Compliance Application ndash Password Controls ndash 2 states

ldquoIf a registered entity has equipment for which a partially or fully compliant

technical solution is available4rdquo

middot ldquoFootnote 4rdquo introduces the term ldquoreasonablerdquo Reasonable is not aterm that is objectively auditable and has in the past been rejected byFERC


ldquoAlthough the standard does not outline what constitutes a good proceduralsolution a sufficient procedural solution would include a compliant policystatement personnel training and other compensating measures such as requiringlonger passwords restricting electronic access and a more frequent password

change cycle6rdquo

middot The Standard does not state what constitutes a good procedural solution Acceptability should be determined through the approval of a TFE not bypromulgating a CAN



middot NPCC participating members suggest that this is the only situation that requires aTFE Equipment that cannot meet the Requirement is different from equipmentnot technically enforcing the Requirement


ldquoWhere a registered entityrsquos technical solution does not have the ability to fullymeet the requirements of R53 the registered entity must have an approved

TFE8helliprdquo

middot This appears to contradict the previous section which indicated that a

TFE was necessary if a technical solution did not enforce theRequirement and there was no procedural solution

middot This contradicts Compliance application Password Controls - R53-3on p 3 of the CAN that states ldquoIf a registered entity has equipment forwhich neither a technical solution nor a procedural solution can beimplemented a registered entity in order to be compliant with thestandard must obtain an approved TFE7rdquo This section is saying thata TFE is needed if only a technical solution is lacking


ldquoattestations from persons responsible for implementing andor complying withthe procedural solutionrdquo


Lee PedowiczManager Reliability StandardsNPCC212-840-1070

From Lee R PedowiczTo cancommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject FW Draft CAN-0018 FAC-008 R121 Terminal EquipmentDate Friday February 18 2011 51844 PM

Following are NPCCrsquos comments on CAN-0018 middot A CAN is for guidance and should not be prescriptive as this ismiddot The Draft CAN-0018 states that terminal equipment is ldquoAny piece of equipment that is in series

with the circuit and that could become a limiting elementrdquo Equipment such as potentialdevices shunt capacitors shunt reactors for example do not meet this criteria as they are notconnected in series with a facility and cannot become a thermally limiting element













-2-




















-3-









1




Standard PRC-023








2












3









4


From Elizabeth HeenanTo rebeccabaldwinspiegelmcdcom LauraLeeduke-energycom MikeGammonkcplcom

jtwoodsoutherncocom hohlbaughdgfirstenergycorpcom mgoldbergiso-necombarrylawsonnrecacoop Lee R Pedowicz brianjmurphyfplcom tefoltzaepcom

Cc davidcooknercnet Sara MingesSubject NERC memo on Section 1700 Following Comment PeriodDate Wednesday March 09 2011 30451 PMAttachments Memo to Board on Section 1700 ROP changes FINALrpdf

Good Afternoon Attached please find a memo from David Cook to the NERC Board of Trustees regarding theproposed Section 1700 to the NERC Rules of Procedure NERC appreciates the comments providedand made a number of changes to accommodate the commenters The memo includes discussionof those comments and proposed changes to section 1700 Thank you













-2-




















-3-









1




Standard PRC-023








2












3









4


From Lee R PedowiczTo rdacommentsnercnetCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to DeterminationsDate Monday March 07 2011 125841 PM

Good afternoon Good afternoon Below are NPCCrsquos Comments to NERCrsquos Proposed Changes to its Rules of Procedure for Compliancefiling in Response to Order 733 - Section 1700 Challenges to Determinations

NERCrsquos Proposed Changes to its Rules ofProcedure for Compliance Filing in Response toOrder No 733 Section 1700- Challenges to Determinations PROPOSED NEW SECTION FOR NERC RULES OF PROCEDURE[DRAFT January 18 2011] SECTION 1700 mdash CHALLENGES TO DETERMINATIONS 1701 Scope of AuthorityWhenever a Reliability Standard or term defined in the Glossary of Terms Used in NERCReliability Standards provides a Registered Entity with the opportunity to challenge adetermination made pursuant to the Reliability Standard or Defined Term this Section 1700 shallset forth the process to be followed Propose deleting This section does not need a general reference to the ldquoGlossary of TermsrdquoA statement about ldquoScope of Authorityrdquo in Section 1700 should be limited to addressingRegistered Entities challenges to determinations made by Planning Coordinators as may beapplicable under PRC-023 only Suggest using 17021 for 1701 1702 Challenges to Determinations by Planning Coordinators Under Reliability StandardPRC-023 1 This Rule 1702 establishes the procedures to be followed when a Registered Entity wishes tochallenge a determination by a Planning Coordinator following the Planning Coordinatorrsquosapplication of the test adopted in Attachment B of PRC-023 to determine the circuits in itsPlanning Coordinator area for which Registered Entities must comply with the standard

Suggest moving this section (17021) to 1701 to establish the ldquoScope of Authorityrdquo andreplace with the following 1 Establishment of processes to challenge Planning Coordinator determinations a A Planning Coordinator shall establish the process for Registered Entities to submit aformal written challenge a determination made by the Planning Coordinator per PRC-023 b A Registered Entity shall follow the process established by the Planning Coordinator toregister formally its request to challenge the determination per these Rules of Procedure This type of provision is needed so that there is no confusion about whether or not theRegistered Entity has provided proper notice to the Planning Coordinator of its intent tochallenge the determination Without following established procedures there may bequestions about whether the notice of the challenge was properly presented to the rightpersonnel at the Planning Coordinator 2 Within 30 days of receiving a written request from a Registered Entity in accordance with17021 a Planning Coordinator shall provide the Registered Entity with a written explanation ofthe basis for its determination under Attachment B of PRC-023 unless the Planning Coordinatorprovided the basis of its determination when it originally informed the Registered Entity of itsdetermination Planning Coordinators and Registered Entities are encouraged to meet informally toresolve any differences This language is not enforceable and does not describe a ldquoprocessrdquo step It should not beincluded in the Rules of Procedure 3 A Registered Entity may challenge the determination of the Planning Coordinator by filing withthe appropriate Regional Entity and the Planning Coordinator within 60 days of receiving thewritten explanation its objection the written explanation from the Planning Coordinator and theRegistered Entityrsquos supporting documents and reasons The challenge may only raise issues thatwere first presented to and discussed with the Planning Coordinator 4 The Regional Entity shall issue its decision within 90 days after it receives the filing TheRegional Entity may convene a meeting of the involved entities and may request additionalinformation 5 Any entity aggrieved by the decision of the Regional Entity may within 30 days of the decisionfile an appeal with NERC with copies to the Regional Entity and the Planning Coordinator orRegistered Entity The appeal shall state the basis of the objection to the decision of the RegionalEntity and shall include the Regional Entity decision the written explanation of the Planning Coordinator and the documents and reasoning filed by the Registered Entity with the RegionalEntity in support of its objection 6 A panel appointed by the NERC Board of Trustees for that purpose shall decide the appealwithin 90 days The panel shall consist of at least three appointees one of whom must be amember of the NERC staff who are knowledgeable about PRC-023 and transmission planning anddo not have a direct financial or business interest in the outcome of the appeal The panel mayrequest additional information from the parties

Regarding the preceding highlighted section better language is needed to establishqualification Perhaps make reference to degrees needed Is this language needed Isnrsquot thisassured by virtue of the fact that the personnel are coming from NERC 7 Any party aggrieved by the decision of the panel may request that the NERC Board of Trusteesreview the decision by filing its request for review and a statement of reasons with NERCrsquos ChiefReliability Officer within 14 days of the panel decision The Board of Trustees may in itsdiscretion decline to review the decision of the panel in which case the decision of the panel shallbe the final NERC decision subject only to an appeal to the applicable governmental authorityfiled within 21 days of the Boardrsquos determination 8 Interested parties are encouraged to resolve any disagreements informally and the involvedparties may make use of alternative dispute resolution procedures at any time during the course ofthe matter

From Elizabeth HeenanTo Lee R Pedowicz rdacomments Sara MingesCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject RE Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to DeterminationsDate Monday March 07 2011 15111 PM

Lee Pedowicz I have received and posted the comments you submitted on behalf of NPCC All comments areposted on the Rules of Procedure webpage under the January 21 postinghttpwwwnerccompagephpcid=1|8|169 Thank you


From Lee R Pedowicz [mailtolpedowicznpccorg] Sent Monday March 07 2011 1258 PMTo rdacommentsCc rsc-members rjfalsetticogecoca donaldenelsonstatemaus lombamrnucomSubject Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to Determinations Good afternoon Good afternoon Below are NPCCrsquos Comments to NERCrsquos Proposed Changes to its Rules of Procedure for Compliancefiling in Response to Order 733 - Section 1700 Challenges to Determinations

NERCrsquos Proposed Changes to its Rules ofProcedure for Compliance Filing in Response toOrder No 733 Section 1700- Challenges to Determinations

PROPOSED NEW SECTION FOR NERC RULES OF PROCEDURE[DRAFT January 18 2011] SECTION 1700 mdash CHALLENGES TO DETERMINATIONS 1701 Scope of AuthorityWhenever a Reliability Standard or term defined in the Glossary of Terms Used in NERCReliability Standards provides a Registered Entity with the opportunity to challenge adetermination made pursuant to the Reliability Standard or Defined Term this Section 1700 shallset forth the process to be followed Propose deleting This section does not need a general reference to the ldquoGlossary of TermsrdquoA statement about ldquoScope of Authorityrdquo in Section 1700 should be limited to addressingRegistered Entities challenges to determinations made by Planning Coordinators as may beapplicable under PRC-023 only Suggest using 17021 for 1701 1702 Challenges to Determinations by Planning Coordinators Under Reliability StandardPRC-023 1 This Rule 1702 establishes the procedures to be followed when a Registered Entity wishes tochallenge a determination by a Planning Coordinator following the Planning Coordinatorrsquosapplication of the test adopted in Attachment B of PRC-023 to determine the circuits in itsPlanning Coordinator area for which Registered Entities must comply with the standard Suggest moving this section (17021) to 1701 to establish the ldquoScope of Authorityrdquo andreplace with the following 1 Establishment of processes to challenge Planning Coordinator determinations a A Planning Coordinator shall establish the process for Registered Entities to submit aformal written challenge a determination made by the Planning Coordinator per PRC-023 b A Registered Entity shall follow the process established by the Planning Coordinator toregister formally its request to challenge the determination per these Rules of Procedure This type of provision is needed so that there is no confusion about whether or not theRegistered Entity has provided proper notice to the Planning Coordinator of its intent tochallenge the determination Without following established procedures there may bequestions about whether the notice of the challenge was properly presented to the rightpersonnel at the Planning Coordinator 2 Within 30 days of receiving a written request from a Registered Entity in accordance with17021 a Planning Coordinator shall provide the Registered Entity with a written explanation ofthe basis for its determination under Attachment B of PRC-023 unless the Planning Coordinatorprovided the basis of its determination when it originally informed the Registered Entity of itsdetermination Planning Coordinators and Registered Entities are encouraged to meet informally toresolve any differences This language is not enforceable and does not describe a ldquoprocessrdquo step It should not be

included in the Rules of Procedure 3 A Registered Entity may challenge the determination of the Planning Coordinator by filing withthe appropriate Regional Entity and the Planning Coordinator within 60 days of receiving thewritten explanation its objection the written explanation from the Planning Coordinator and theRegistered Entityrsquos supporting documents and reasons The challenge may only raise issues thatwere first presented to and discussed with the Planning Coordinator 4 The Regional Entity shall issue its decision within 90 days after it receives the filing TheRegional Entity may convene a meeting of the involved entities and may request additionalinformation 5 Any entity aggrieved by the decision of the Regional Entity may within 30 days of the decisionfile an appeal with NERC with copies to the Regional Entity and the Planning Coordinator orRegistered Entity The appeal shall state the basis of the objection to the decision of the RegionalEntity and shall include the Regional Entity decision the written explanation of the Planning Coordinator and the documents and reasoning filed by the Registered Entity with the RegionalEntity in support of its objection 6 A panel appointed by the NERC Board of Trustees for that purpose shall decide the appealwithin 90 days The panel shall consist of at least three appointees one of whom must be amember of the NERC staff who are knowledgeable about PRC-023 and transmission planning anddo not have a direct financial or business interest in the outcome of the appeal The panel mayrequest additional information from the parties Regarding the preceding highlighted section better language is needed to establishqualification Perhaps make reference to degrees needed Is this language needed Isnrsquot thisassured by virtue of the fact that the personnel are coming from NERC 7 Any party aggrieved by the decision of the panel may request that the NERC Board of Trusteesreview the decision by filing its request for review and a statement of reasons with NERCrsquos ChiefReliability Officer within 14 days of the panel decision The Board of Trustees may in itsdiscretion decline to review the decision of the panel in which case the decision of the panel shallbe the final NERC decision subject only to an appeal to the applicable governmental authorityfiled within 21 days of the Boardrsquos determination 8 Interested parties are encouraged to resolve any disagreements informally and the involvedparties may make use of alternative dispute resolution procedures at any time during the course ofthe matter This email and any of its attachments may contain information that is privilegedconfidential classified as CEII or subject to copyright belonging to NPCC This email isintended solely for the use of the individual or entity to which it is addressed If you are notthe intended recipient of this email you are hereby notified that any disseminationdistribution copying or action taken in relation to the contents of and attachments to thisemail is strictly prohibited and may be unlawful If you receive this email in error pleasenotify the sender immediately and permanently delete the original and any copy of this email

and any printout

Agenda 3-16-11


Preliminary Agenda--Draft

Meeting 11-2



MOD-025-RFC-01 - Verification and Data Reporting of Generator Gross and Net Reactive Power Capability passed its 15 day Category vote and was approved by the RFC Board of Directors at their March 3 2011 Meeting


l NERC Operating Committee March 8-9 2011 Meeting--notes

m NERC Planning Committee March 8-9 2011 Meeting--notes





Action Item List

Action_Item_68--NPCC Regional Reliability Standards Development Procedure BG_KC_v1 0

Steps 1 and 2 Request to Develop a New Regional Standard

Steps 3 4 and 5 RSC Accepts RSAR and RCC Assigns TF to Draft New or Revised Standard

Step 6 Solicit Public Comments on Draft Regional Standard

Steps 7 8 and 9 Open Process Posting and Analysis of the Comments

Steps 10 and 11 RSC Approves of the New or Revised Standard For Posting

Appendix A








Related Standards

-t


Action_Item_69--RSC Scope Revision for BOD ApprovalRev5Draft 2 24 11 redline

Item_1a--Draft for Comment 2-8-11 BOD Minutes

Item_2--Minutes--RSC_2-2-11_Meeting--Draft--3-1-11


Draft Minutes for Approval

Meeting 11-1



MOD-025-RFC-01 - Verification and Data Reporting of Generator Gross and Net Reactive Power Capability passed its 15 day Category vote Anticipated RFC Board of Directors action to approve to approve during their March 3 2011 m


The RSC November Meeting dates have to be changed because of a conflict with the NPCC Annual and General Meetings

Meeting adjourned 1221 Feb 3 2011





Action Item List

Item_4a--Standards Development Executive Tracking Summary 3 10 11

NERC RS Exec Tracking Summary

NPCC RRS Tracking Summary

NPCC Doc Tracking Summary

NPCC Directory Tracking Summary

Item_5a--FERC_2-17-11_Meeting_Agenda

Item_5b--March 17 FERC Open Meeting Agenda

Item_5b--March 17 2011 FERC Open Meeting Agenda

Item_5-T1--FW_ NERCs Draft Response to FERCs Notice of Proposed Rulemaking (NOPR)_ The Integration of Variable Energy Resources

Item_5-T1--NERC_draft_VER_NOPR_comments_02-25-11

Item_5-T2--20110228-5264(25060793)

Final_NUC_filing_DraftQ42010_20110228(PUBLIC)PDF

Document Content(s)

Item_5-T2--GZ_E-mail--Answer_Response to a Pleading_Motion submitted in FERC RM06-16-000 by North American Electric Reliability Corporationet al

Item_5-U1--FW_ Commission Order_Opinion issued in FERC RM06-22-014

Item_5-U1--Mandatory_Reliability_Standards_for_CIP_March_18_2010

I Background

II NERC Compliance Filing

III Notice and Responsive Pleadings

IV Commission Determination

Item_9a--2009-02_RTTSDT_Third_Posting_SAR_Redline_Last_Posting_2010April1

Standard Authorization Request Form



Related Standards

Related SARs

Regional Variances

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

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


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

Applicable Reliability Principles (Check box for all that apply)

Explanation

Standard No

Explanation

SAR ID

Explanation

Region

Item_9a--Project_2009-02_rmacsdt_white_paper_021611

10 INTRODUCTION

20 MONITORING

21 PERFORMANCE

211 Status Data

212 Analog Data

213 Data Display

22 AVAILABILITY


24 MAINTENANCE

30 DATA EXCHANGE

31 PERFORMANCE

32 AVAILABILITY


34 MAINTENANCE

40 ALARMING

41 PERFORMANCE

42 AVAILABILITY


44 MAINTENANCE

50 ANALYSIS

51 PERFORMANCE

511 Periodicity

512 Results Quality

52 AVAILIBILITY


54 MAINTENANCE

Item_9a--RE_ RSC Meeting--March 16-17 2011

Item_9a--Standards Announcement - Informal Comment Period Open - Project 2009-02 Real-time Monitoring and Analysis Capabilities

Item_9b--Comment Period Opens for Proposed Changes to ReliabilityFirst Corporation Rules of Procedure Pertaining to Regional Standards Development Process

Item_9b--Final_Posting_RFC_Standards_Process_Changes_20110301

Transmittal of Revised SDP to NERC - 2011014pdf

Att A - RFC_Reliability_Stds_Development_Procedure_V3_121510pdf

ReliabilityFirst CorporationReliability Standards Development Procedure

Version 3

ReliabilityFirst Corporation Reliability Standards Development ProcedureTable of Contents

ReliabilityFirst Corporation Reliability Standards Development Procedure

Introduction

Regional Reliability Standard Format Requirement Template Example

Maintenance of Regional Reliability Standards Development Process

Appendix B

Standard Authorization Request

SAR Originator Information

Name


Related Standards (NERC and Regional)

Related SARs

Implementation Plan

Assignments

Assignment

Team Members

ReliabilityFirst Staff

Appendix C

Appendix D

Ballot Pool Categories

For the purposes of category Ballot Pool registration and voting a person or entity may join the registered Ballot Pool to vote on standards whether or not such person or entity is a member of ReliabilityFirst

A corporation or other organization with integrated operations or with affiliates that qualifies to belong to more than one category (eg Transmission Owners and Load Serving Entities) may join and vote once in each category for which it qualifies provided that each category constitutes a separate membership in the Ballot Body and the organization is represented in each category by a different representative Affiliated entities are collectively limited to one membership in each category in the Ballot Pool for which they are qualified

Category 1 ndash Transmission Owner Transmission Operator Transmission Service Provider

Item_9c--Final_Posting_Appendices_3B_3D_20110301 (3)


Purpose


Guiding Principles







Election Formula


Special Elections




Purpose


Guiding Principles







Election Formula


Special Elections




Purpose


Guiding Principles







Election Formula


Special Elections



Final_Appendix_3Dpdf




Segments












Purpose


Guiding Principles







Election Formula


Special Elections




Purpose


Guiding Principles







Election Formula


Special Elections



Final_Appendix_3D(CLEAN)pdf

Appendix 3D mdash Development of the Registered Ballot Body0F



Segments










Segment 10 Regional Entities

Final_Appendix_3D(REDLINE)pdf




Segments











Item_9c--FW_ Comment Period Opens for Proposed Changes to NERC Rules of Procedure Appendices 3B and 3D

Item_9d--2010-07_Attachment 1_FAC-001-0

Version

Item_9d--2010-07_Attachment 2_FAC-003-2_Draft_5





Effective Dates

Version History


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

Vegetation Inspection

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 preventin

4 Applicability

41 Functional Entities

Transmission Owners

42 Facilities Defined below (referred to as ldquoapplicable linesrdquo) including but not limited to those that cross lands owned by federal0F state provincial public private or tribal entities

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


R1 Each Transmission Owner and Generator Owner shall manage 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 Intercon


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



R2 Each Transmission Owner and Generator Owner shall manage 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 withi


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



Compliance

Time Horizons Violation Risk Factors and Violation Severity Levels

Variances

Interpretations

None


Requirement R7

FAC-003 mdash Table 2 mdash Minimum Vegetation Clearance Distances (MVCD)4F

Item_9d--2010-07_White_Paper_Proposal_for_Informal_Comment

Introduction

Objective

Proposed Next Steps and Review of Reliability Standards

Summary and Discussion of Other Solutions

Item_9d--Project_2010-07_Standards_Announcement_030411

Item_9e--EOP-004-2_redline_to_last_posting_20110308





Effective Dates

1 USA The standard shall become effective on the Ffirst calendar day of the firstthird calendar quarter one year after the date of the order providing applicable regulatory authority approval for all requirements

2 Canada and Mexico First calendar day ofConcurrent with the first calendar quarter one year following Board of Trustees adoption unless governmental authority withholds approvalEffective Date for the USA In those jurisdictions where no regulatory

Version History


None

Impact Event Any event which has either impacted or has the potential to impact the reliability of the Bulk Electric System Such events may be caused by equipment failure or mis-operation environmental conditions or human action

Introduction

1 Title Impact Event and Disturbance Assessment Analysis and Reporting

2 Number EOP-004-2

3 Purpose Responsible Entities shall report impact events and their known causes to support situationalTo improve industry awareness and the reliability of the Bulk Electric System (BES)by requiring the reporting of Impact Events and their causes if k

4 Applicability

41 Functional Entities Within the context of EOP-004-2 the term ldquoResponsible Entityrdquo shall mean

411 Reliability Coordinator

412 Balancing Authority

413 Interchange Authority

414 Transmission Service Provider

415 Transmission Owner

416 Transmission Operator

417 Generator Owner

418 Generator Operator

419 Distribution Provider

411 Electric Reliability Organization


R3

R2 Each ApplicableResponsible Entity shall identify and assess initial probable cause of impact events listed in Attachment 1 in accordance with itsimplement its Impact Event Operating Plan documented in Requirement R2R1 for Impact Events listed i

Compliance

Variances

Interpretations

EOP-004 - Attachment 1 Impact Events Table

EOP-002004 - Attachment 2 Impact Event Reporting Form


Introduction

Summary of Concepts and Assumptions

Discussion of Disturbance Reporting

Discussion of ldquoimpact eventImpact Eventrdquo Reporting

Collection of Reportable Information or ldquoOne stop shoppingrdquo

Item_9e--Project_2009-01_CIP-001-1

Version History

Item_9e--Project_2009-01_EOP-004-1

Version History

Table 1-EOP-004-0

Summary of NERC and DOE Reporting Requirements for Major Electric System Emergencies

All entities required to file a DOE EIA-417 report (Schedule 1 amp 2) shall send a copy of these reports to NERC simultaneously but no later than 24 hours after the start of the incident or disturbance

Item_9e--Project_2009-01_Implementation_Plan_20110308

The standard shall become effective on the first calendar day of the third calendar quarter after the date of the order providing applicable regulatory approval In those jurisdictions where no regulatory approval is required the standard shall becom

Item_9e--Project_2009-01_Standards_Announcement_030911

Item_11a--FW_ Comment Form--Project 2010-11 - TPL Table 1 Order

Item_11a--Standards Announcement - Recirculation Ballot Window Open January 26-February 5 2011 - Project 2010-11 TPL Table 1 Order

Item_11a--Standards Announcement_ Recirculation Ballot Results _ Project 2010-11 TPL Table 1 Footnote B

Item_11b--FW_ Standards Announcement_ Project 2007-07 Transmission Vegetation Management - Successive Ballot Results

Item_11b--Project 2007-07 ― Vegetation Management ― FAC-003

Item_11b--Standards Announcement - Successive Ballot and Non-binding Poll Open _ Project 2007-07 Vegetation Management

Item_11c--FW_ Standards Announcement_ Project 2006-06 ndash Reliability Coordination _ Initial Ballot Results

Item_11c--NERC Ballot for Project 2006-06 Reliability Coordination COM-001 COM-002 IRO-001 and IRO-014

Item_11c--NERC Initial Ballot NPCC Recommendation-Project 2006-06 ― Reliability Coordination ― COM-001 COM-002 IRO-001 and IRO-014

Item_11c--Standards Announcement - Ballot Window Open February 25 - March 7 2011 _ Project 2006-06

Item_11d--FW_ Standards Announcement_ Non-binding Polls for VSLs Now Open - October 27-November 6 2010 _ Project 2007-23

Item_11d--Standards Announcement - Project 2007-23 _ Violation Severity Levels

Item_11d--Standards Announcement_ Results of Non-Binding Poll of VSLs _ Project 2007-23 Violation Severity Levels

Item_11e--FW_ Please Cast Your Vote Today for the Relay Loadability Order 733 Ballot _ Project 2010-13

Item_11e--Standards Announcement - Project 2010-13 - Relay Loadability Order 733 Modifications

Item_11e--Standards Announcement_ Project 2010-13 Relay Loadability for Order 733 - Successive Ballot Results

Item_11f--BOT memo updating on votong on PRC-023-2 and RSDP 20110309L

Item_11f--FW_ Please Cast Your Vote Today for the Relay Loadability Order 733 Ballot _ Project 2010-13

Item_11f--Standards Announcement - Recirculation Ballot Window Open February 24 - March 6 2011 _ Project 2010-13

Item_11f--Standards Announcement_ Project 2010-13 ndash Relay Loadability Order _ Recirculation Ballot Results

Item_13a--Unofficial_Comment_Form_for_Standards_Committee_Posting_of_Prioritization_Tool--2-10-11

Unofficial Comment Form for Standards Committeersquos Project Prioritization Reference Document and Tool


During the past few years the Standards Committee has been presented with more proposals for developing new or revised projects than can be accomplished at one time The project prioritization tool is an excel spreadsheet that provides a transparent


Item_13b--2007-12_BAL-003-1_Comment_Form--Submitted--3-7-11



Item_13c--Submitted_3-7-11--Comment_Form--Project-2007-12_BAL-003-1



Item_13d--LP--Comments_Project2007-23_2-18-11 Submitted




Item_13e--LP--Submitted_3-7-11--Project_2006-06_RC_COMMENT_FORM_RSC--2-28-11

Comment Form for Reliability Coordination ndash Project 2006-06




Alternative Interpersonal Communication Any method Interpersonal Communication that is able to serve as a substitute for and is redundant to normal Interpersonal Communication and does not utilize the same infrastructure (medium) as normal Interpe

Item_13g--FW_ Draft CAN-0015 Unavailability of NERC Tools

Item_13h--Draft CAN-0016 CIP-001-1 R1 - Applicability to Non-BES

Item_13i--Draft CAN-0017 CIP-007 R5 System Access and Password Controls

Item_13j--FW_ Draft CAN-0018 FAC-008 R121 Terminal Equipment

Item_13k--Memo to Board on Section 1700 ROP changes FINALr

Item_13k--NERC memo on Section 1700 Following Comment Period

Item_13k--Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to Determinations

Item_13k--RE_ Proposed Changes to Rules of Procedure to Add Section 1700 - Challenges to Determinations

Member

Organization

Region

Segment Selection

1

Adamson Alan

New York State Reliability Council LLC

NPCC

10

2

Guy Zito

Northeast Power Coordinating Council

NPCC

10

3

Campoli Gregory

New York Independent System Operator

NPCC

2

4

Chong Kurtis

Independent Electricity System Operator

NPCC

2

5

Clermont Sylvain

Hydro-Quebec TransEnergie

NPCC

1

6

Dackow Bohdan M

US Power Generating Company (USPG)

NPCC

---

7

De Graffenried Chris


NPCC

1

8

Dunbar Gerry

NPCC

NPCC

10

9

Evans-Mongeon Brian D

Utility Services

NPCC

8

10

Garton Mike

Dominion Resources Services Inc

NPCC

5

11

Gooder Brian L

Ontario Power Generation Incorporated

NPCC

5

12

Goodman Kathleen

ISO - New England

NPCC

2

13

Haswell Chantel

FPL Group Inc

NPCC

5

14

Kiguel David

Hydro One Networks Inc

NPCC

1

15

Lombardi Michael R

Northeast Utilities

NPCC

1

16

MacDonald Randy

New Brunswick Power Transmission

NPCC

1

17

Metruck Bruce


NPCC

6

18

Pedowicz Lee

NPCC

NPCC

10

19

Pellegrini Robert

The United Illuminating Company

NPCC

1

20

Saksena Saurabh

National Grid

NPCC

1

21

Schiavone Michael

National Grid

NPCC

1

22

Sipperly Wayne


NPCC

5

23

Weaver Donald

New Brunswick System Operator

NPCC

2

24

Wu Ben

Orange and Rockland Utilities

NPCC

1

25

Yost Peter


NPCC

3

Gerald W Cauley


David N Cook





(609) 452-8060


s Willie L Phillips

Holly A Hawkins

Attorney

Willie L Phillips

Attorney


1120 G Street NW

Suite 990

Washington DC 20005-3801

(202) 393-3998

(202) 393-3955 ndash facsimile

Gerald W Cauley


David N Cook



Corporation



(609) 452-8060


Persons to be included on FERCrsquos service list are indicated with an asterisk NERC requests waiver of FERCrsquos rules and regulations to permit the inclusion of more than two people on the service list

Holly A Hawkins

Attorney

Willie L Phillips

Attorney


1120 G Street NW

Suite 990


(202) 393-3998


Gerald W Cauley


David N Cook



Corporation



(609) 452-8060


Holly A Hawkins

Attorney

Willie L Phillips

Attorney


1120 G Street NW

Suite 990


(202) 393-3998


NPCC Regional Standards Committee Preliminary Agenda--Draft … · 2020. 10. 15. · Compliance...

Documents

Transcript of NPCC Regional Standards Committee Preliminary Agenda--Draft … · 2020. 10. 15. · Compliance...

image1png

Background Information

image1png

Background Information