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North American Electric Reliability CouncilPrinceton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731

OPERATING COMMITTEE MEETING

March 11, 1997 & 10:156noonMarch 12, 1997 & 8 a.m.6noon

Hotel Del CoronadoCoronado (San Diego), California

AGENDA

Introduction and Administration

Background Material Included

1. Administrative Mattersa. Introductionsb. Determination of a Quroum & Donald M. Benjaminc. Arrangements & Donald M. Benjamind. Approval of Agenda & Gregory A. Cucchie. Organization and Assignments Chart 88

2. Chairman’s Comments & Gregory A. Cucchia. Board of Trustees Meeting, January 667, 1997 88

3. Consent Agendaa. Minutes of December 364, 1996 Meeting

4. Operating Commmittee Organization and Procedures 88

a. Subgroupsi) Telecommunications Subcommittee replaced by Telecommunications

and Data Exchange Working Groups who report to SCS. Assign SCSresponsibility for Policy 7.

ii) Disturbance Analysis Working Group revised scope 88

iii) Security Process Support System Task Force scopeb. Organization and Procedures Document 88

i) Parliamentary Procedures & Donald M. Benjaminii) OC Executive and Steering Committee & William C. Phillipsiii) E-mail voting & Donald M. Benjaminiv) Policy implementation process & Charles V. Waits

c. Due Process and Appeals & Kurt J. Conger 88

d. OC Meeting Schedule: Fourth Meeting & Gregory A. Cucchi


Compliance Issues

5. Manitoba Hydro Generation Loss && September 5, 1996 88

a. MAPP follow-up (including NSP actions) & Sheldon L. Bergi) Role of Security Coordinator & C.M. Mennes

b. NERC Policies: Can a single party cut a schedule?

6. WSCC July 2663 and August 10, 1996 Events Follow-up && Theodore A. Reece 88

Continue to follow upa. Policy changes & Subcommittee chairsb. Compliance procedure flowchart & Eugene P. Byars

7. ERCOT January 28 High Demand & Sam R. Jones 88

8. Inadvertent Interchange: Balances in Western Interconnection & Albert M. DiCaprio 88

Action Items & Policies

9. Result of Vote on Policies 1, 3E, and 7 88

Summary of Regional votes and follow-up on Subcommittee Assignments

10. Policy 3 and 4, Appendix 3A and 3B & Derek R. Cowbourne 88

11. Standards 88

List of possible Standards from each Subcommittee chaira. Policy 1 & Albert M. DiCapriob. Policies 2, 3, and 4 & Walter A. Johnsonc. System Operator Certification and Training Course Accreditation &

Jay Lanning, Ray Gross

12. Disturbance Analysis Working Group & Edward C. Eakeley 88

Disturbance reporting Policies

Action Items & Other

13. Interconnection Operations Services Working Group 88

Discussion Items

14. Implementation of IOServices in Operating Policies & Donald M. Benjamin

15. Security Process Support Task Force & Robert W. Cummings, Louis G. Leffler

16. Future of Monitoring Working Group & R. Kenneth Wilkerson


17. Security Coordinator Subcommittee & C.M. Mennes

18. Policy Voting Procedures & Gregory A. Cucchi

19. After-the-Fact Transaction Changes & Albert M. DiCaprio

20. Reliability Assessment Subcommittee & David A. Whiteley 88

21. Formation of Commercial Practices CommitteeOr Transmission Marketing Operations Committee, or whatever.

22. Operating Issues & Roundtable

23. Future Meetings 88

Agenda Item 1eOC MeetingMarch 11612, 1997

NERC OPERATING COMMITTEE ORGANIZATION AND ASSIGNMENTS

Chairman: Greg Cucchi Vice Chairman: Bill Phillips Secretary: Don Benjamin Past Chairman: Gene Byars

ECAR TermTony Geswein 5/98OPS

Charles Waits 5/97

ERCOT TermJim Byrd openIOS

Ross Phillips open

FRCC TermMarty Mennes

Joe Krupar

MAAC TermBruce Balmat openOPS

Walter Johnson ??IOS

MAINMark Westendorf ??

Dan Gorski 1/99 IOS

MAPPShel Berg openOPS

Jerry Hagge 1/98IOS

NPCCBob Wolff open

Tim Bush open

Derek Cowbourne openIOS-Ch

SERCBill Thompson

Steve Whitley 11/97

John Pope 10/98IOS

SPPHenry Janhsen 1/00IOS

Gerry Burrows 1/98OPS

WSCCTed Reece openOPS

Rich Nassief openIOS

Ron Hallford open

Mark Meyer openOPS

POWER MARKETERTo be named

To be named

COOPERATIVELarry HuffTS

Dennis Wright

IPPDarrell Hayslip

To be named

CANADAEarle T. Floyde

Operating Committee Observers

William Booth FERCKurt Conger APPALynn Coles APPA AlternateGlenn Coplon DOEVeikko Kammonen CEAMike Trykoski EEI

Operating Committee Steering Committee

Bill Phillips OC Vice ChairmanGreg Cucchi OC ChairmanGene Byars Past OC ChairmanChuck Waits ECARSam Jones ERCOTMarty Mennes FRCCBruce Balmat MAACDan Gorski MAINJerry Hagge MAPPDerek Cowbourne NPCCSteve Whitley SERCHenry Janhsen SPPTed Reece WSCCGarey Rozier EC Liaison

Performance Subcommittee %% Policy 1

Al DiCaprio MAACDoug Hils ECARDennis Hogan ERCOTDon McInnis FRCCHoward Illian MAINAlan Oneal MAPPMike Potishnak NPCCGary Rudder SERCBill Phillips SPPMirek Horenovsky RMPPGrant Griffith NWPPEd Riley CANVPhil Clark AZNMColin Wright NERC

Term

10/97

Interconnected OperationsSubcommittee %% Policies 2, 3, 4

Derek Cowbourne NPCCBob Kelley ECARJim Byrd ERCOTRon Donahey FRCCWally Johnson MAACDan Gorski MAINJerry Hagge MAPPJohn Pope SERCHenry Janhsen SPPRich Nassief WSCCTerry Bundy ECPat Connors MunicipalTo be named MarketerDarrell Hayslip IPP

Term

2/98

Operations PlanningSubcommittee Policies 5, 6

Walt Campbell SERCTony Geswein ECAREllis Rankin ERCOTJoe Krupar FRCCBruce Balmat MAACShel Berg MAPPBob Wolff NPCCWalt Campbell SERCGerry Burrows SPPMark Meyer WSCCTed Reece WSCC

Term

6/99

Security Coordinator SubcommitteePolicy 7

Marty Mennes SERCJack Maurer ECARBob Kelley ECARJim McMahon ECARSam Jones ERCOTCharlie Woodward MAACDave Hilt MAINShel Berg MAPPDerek Cowbourne NPCCPeter Czech NPCCWayne Snowdon NPCCPaul Shortley NPCCTim Bush NPCCJohn Pope SERCLloyd Lundin SERCBill Thompson SERCEddie Stubbins SERCBill Phillips SPPMike Rogers WSCCDarrel Van Coevering WSCCEd Hulls WSCCBob Smith WSCC

System Operator SubcommitteePolicy 8

Jay Lanning SERCBob Thompson ECARBilly Helpert ERCOTChuck Harper FRCCRay Gross MAACShawn Schukar MAINDrew Phillips NPCCDennis Szymanski MAPPMarty Sidor SPPBill Comish WSCCDon Splinter Power

Marketer

Term

11/97

Monitoring Working Group

Randy WilkersonDave Dietz&

Term

open

RAS

Shel Berg

Term

10/98

Disturbance Analysis Working Group

Ed Eakeley WSCCPhil Winston SERCMike McGeeney SPPTim Bush NPCCEd Eakeley WSCCBob Harbour (EC) MAINPaul Rychert (EC) MAACJay Lanning (SOS) SERCGene Gorzelnik NERC

Other Assignments

Joint EC/OC Subgroups

Transmission Reservation andScheduling Task Force

Art Garfield MAINDave Benson ECARScott Moore ERCOTTed Hobson FRCCKen Laughlin MAACHarry Terhune MAINJerry Hagge MAPPJohn Koehler NPCCJohn Pope SERCHenry Janhsen SPPJim Dyer WSCCPaul Barber Power MarketerJolly Hayden Power MarketerSarah Barpoulis Power MarketerFreddy Sanches Power MarketerDarrell Hayslip IPPRay Wahle TDUManual Canalita TDUTerry Boston FederalBen Li CanadaBill Phillips EEI LiaisonColin Wright NERC

ATC Implementation Working Group

Paul Johnson ECARLee Westbrook ERCOTMarty Mennes FRCCBob Reed MAACKirit Shah MAINTom Mielnik MAPPStanley Kopman NPCCGlenn Ross SERCTom Mallinger SPPSteve Walton WSCCJohn Lindberg Power MarketerDean Perry FederalTo be named IPPPat Connors TDUPaul Barber TRSTS LiaisonSam Daniel RCS LiaisonDerek Cowbourne IOS LiaisonMichael Falvo CanadaBrian Nolan NERC

Agenda Item 2OC MeetingMarch 11612, 1997


NORTH AMERICAN ELECTRIC RELIABILITY COUNCILBOARD OF TRUSTEES MEETING

January 6–7, 1997Litchfield Park, Arizona

MEETING HIGHLIGHTS

The North American Electric Reliability Council Board of Trustees met on January 6–7,1997. Highlights of the meeting include:

Bylaws

The Board unanimously approved changes to the Membership Obligations section of theBylaws, obligating the Regional Councils and their members to comply with NERC Policies.

Options to Ensure Compliance

The Board:

— Unanimously accepted the “Options to Ensure Compliance” report and committed tomove forward in the directions suggested by the “Next Steps” section of the report,

— Directed the Future Role of NERC Task Force — II to oversee the implementation ofthese “Next Steps.” The Task Force will provide direction to the EngineeringCommittee, Operating Committee, and staff, as appropriate, and regularly report progressto the Board, and,

— Directed the Future Role of NERC Task Force — II to report to the Board any projectsand initiatives required to satisfy the “Next Steps” that have significant policyimplications and/or that require major new funding.

Strategic Initiatives for NERC

Security Process — The Board unanimously approved the scope and formation of a SecurityCoordinator Subcommittee of the Operating Committee to primarily oversee the implementation andmaintenance of Regional and subregional security plans and processes. It also approved:

— Implementation of a Confidentiality Agreement for data sharing among control areas andsecurity coordinators to allow these entities to perform security analyses;

— Development of an Interregional Security Network (ISN), which is a telecommunicationsnetwork to enable data sharing;

— Development of an Interchange Distribution Calculator (IDC) to predetermine the effectsof interchange transactions on all transmission paths; and

— Implementation of a Transaction Information System (TIS) to provide a uniform methodfor “tagging” interchange transactions.

Operating Standards — The Board endorsed the Operating Committee’s approach todeveloping new and revised Operating Standards. It also approved the Operating Committee’s actionplans to develop and implement a NERC-wide System Operator Certification Program and a NERC-wideAccreditation Program for System Operator Training Programs, and a new operator training tutorial onSystem Restoration.

Planning Standards — The Board approved the Engineering Committee proceeding with theimplementation of its “Proposed Action Plan” to establish revised and new NERC Planning Standardsand Guides.

Transmission Reservation and Scheduling/Available Transfer Capability — The Boardagreed that the Engineering and Operating Committees should proceed with the development and testingof a trial flow-based transmission reservation and scheduling system as conceptually described in theTransmission Reservation and Scheduling Task Force’s report.

Response to DOE Recommendations

The Board approved proceeding with the programs and activities required to respond to therecommendations contained in DOE’s August 2, 1996 report to the President, under the direction of theFuture Role of NERC Task Force — II.

Additional Future Role of NERC Initiatives

The Board approved the Future Role of NERC Task Force — II overseeing work on thefollowing additional initiatives: development of an industry compact; defining reliability functions;development of a framework for enforcement measures; dispute resolution; review of NERC’sadministration.

New Operating Committee Organization and Procedures Document

The Board approved the Operating Committee’s new Organization and ProceduresDocument.

NERC Budget Revisited

The Board approved a special assessment of its Members for 1997 of $1,500,000 to provideNERC with the resources needed to implement the new and expanded projects approved by the Board.


Operating Committee Organization and Procedures

4.a. Subgroups

4.a.i. Telecommunications Subcommittee replacement. Several months ago the Telecom-munications Subcommittee formed two working groups to develop the hardware and databaserequirements for the Interregional Security Network. The Telecommunications Working Group hasbeen defining the frame relay structure and the requests for proposal that NERC has sent to several framerelay vendors. The Data Exchange Working Group has been developing the database requirements anddata exchange protocols over the ISN. Both of these working groups report to the Security CoordinatorSubcommittee. Their scopes are attached.

The Telecommunications Subcommittee believes that it is no longer needed and that its functionscan be handled by these two working groups. The Security Coordinator Subcommittee will beresponsible for Operating Policy 7, • “Telecommunications.”

Action: 1. Dismiss Telecommunications Subcommittee2. Approve scopes for Telecommunications Working Group and Data Exchange Working

Group3. Assign responsibility for Policy 7 to Security Coordinator Subcommittee

4.a.ii. Disturbance Analysis Working Group. The DAWG has several changes to make to its scopeas the Working Group takes a more active role in disturbance reviews. Working Group chair Edward C.Eakley will review this group’s expanded draft scope, which is attached. (The present DAWG scopefollows the proposed draft). See also Item 12.

Action: Discuss draft DAWG scope for approval.

4.a.iii. Security Process Support System Task Force. Robert W. Cummings will review this proposeddraft scope at the joint EC/OC meeting. Each committee will approve the scope at its respectivemeetings. The draft scope statement is attached and includes an explanation of the purpose of this TaskForce.

Action: Discuss draft SPSSTF scope for approval

4.b. OC Organization and Procedures Document.

The Operating Committee needs to address several suggested changes to itsorganization and procedures. The OC Organization Document, which the NERC Board ofTrustees approved at its January 1997 meeting, is attached with the suggested changes marked.Most of these revisions will require Board of Trustees approval.

4.b.i. Parliamentary Procedures. The OC Organization Document states that thecommittee will follow Robert’s Rules of Order unless stated otherwise. The OC’s procedures dodepart from Robert’s Rules in several areas, especially in voting methods. While this isacceptable to Mr. Robert, the reasons for this departure are not obvious. For example, Committeemembers who abstain from voting on a motion are actually part of the tally of “no” votes. DonBenjamin will explain where the Committee’s procedures are different from the standard rules oforder and suggest specific changes. These are summarized in the table below and reflected in themarked-up version of the OC Organization Document that it attached.

Subject Current Procedure Comments Robert’s Rules

Voting calculation No. of “yes” divided byattendance

Abstentions count as“no’s”

No. of “yes” divided byNo. of “yes” + No. of“no”

Chair as a member withvoting righs.

No Can’t vote. If Chair is a member, hecan vote if it affects theoutcome.

Marjority requirements 2/3 Simple majority

Action: Discuss for approval.

4.b.ii. OC Executive and Steering Committees. The Operating Committee ExecutiveCommittee consists of the Committee officers plus the subcommittee chairs. From theOrganization Document:

The Executive Committee may exercise all the powers of the Committeebetween meetings of the Committees. Any action taken by the ExecutiveCommittee will be submitted for ratification at the next meeting of the fullOperating Committee.

The Steering Committee’s responsibilities are to:

1. Identify concerns and recommend Operating Committee activities that enhanceinterconnected systems operation

2. Identify and assist in formulating issues to provide clearly delineated direction to the OCsubgroups.

3. Assist the Chairman in setting a focused agenda.

4. Assess subgroup progress and recommendations to the OC.

5. Administer subgroup membership.

6. Serve as the initial contacts for reporting on special operating events.1 (Refer to “Reportingon Special Events” in the Procedures section of the Operating Committee Handbook).

The Steering Committee met on January 27, 1997 to address several OC organizationissues. One of its conclusions was that its “housekeeping” functions would be moreefficiently served by a small executive committee consisting of only the OperatingCommittee’s officers. This executive committee would then invite Regionalrepresentatives or subcommittee chairs or both as needed, depending on the agenda. TheExecutive Committee would also become responsible for forming task forces to address“special events.” The Steering Committee would be dismissed.

Action: 1. Reorganize the Executive Committee to consist of the OC Officers (Chair,vice chair, past chair, secretary) plus a member-at-large whom the chairappoints. (This is the same structure as the NERC Executive Committee).

2. Dismiss the OC Steering Committee.

4.b.iii. E-mail voting. E-mail voting allows the OC to decide on issues without a “physical”meeting; however, the Committee must address the basic rules of order: determining a quorum,making the motion, seconding the motion, allowing for debate, and voting. Don Benjamin willreview the following suggestions on e-mail voting:

Voting on a pending motion. A pending motion is one that is currently before the Committeeand has not been voted on. The Committee can postpone the vote on a pending motion to an e-mail vote as long as the debate has been completed and someone “calls for the question.” Forexample, the OC may have a pending motion to change a Standard, but decide that it cannot voteon the motion until the Committee members debate the subject within their Regions. Assumingthe debate among the Committee is complete, the motion can be Postponed to a Certain Time atwhich it will then be voted by e-mail. It would then be approved with a 2/3 majority of the totale-mail votes cast.

If a motion does not exist. This situation requires conducting business via e-mail, and the basicrules of order aren’t possible. The Committee has two options: 1) meet by conference call sothat a quorum, second, and debate can be accommodated, or 2) allow the OC ExecutiveCommittee to act on the issue, with ratification at the following OC meeting.


1The OCSC will be joined by the chairman of the Disturbance Analysis Working Group plus

the Engineering Committee vice chairman.

4.b.iv. Policy Implementation Process. Chuck Waits will present several suggestions onPolicy implementation.


4.c. Due Process and Appeals

At the December 1996 OC meeting, chair Cucchi asked Kurt Conger, APPA’s observerto the OC, to recommend a due process and appeals process. Mr. Conger will discuss the draftdocument “NERC Operating Standards and Policies Proposed Amendments to Organization andProcedures to Ensure Due Process and Appeals.” The draft is attached.

Action: Discuss suggested changes for approval.

4.d. OC Meeting Schedule: Fourth meeting?

At its last meeting, the Operating Committee agreed that it should add a fourth meeting toaddress the myriad issues that NERC is dealing with. The Chair would like to revisit this issue todiscuss the underlying issues more thoroughly. For example, does the Committee need more timeto debate its motions, or is the Committee not receiving the background information it needs tomake its decisions.

Action: Revisit need for additional meetings.

Agenda Item 4.a.iOC MeetingMarch 11 12, 1997

NERC ISN TELECOMMUNICATIONS WORKING GROUPSCOPEDECEMBER 1996

NERC ISN

The NERC Interregional Security Network (ISN) provides timely and accurate data and information toassist those charged with assuring secure interconnected transmission system operation.

PURPOSE

The ISN Telecommunications Working Group (TWG) oversees the telecommunications, which supportsthe ISN.

The Security Process Implementation Timeline shows the ISN in place for initial data input by 01 June1997; the Working Group will work to meet this objective.

REPORTING AND COMPOSITION

The TWG reports and makes recommendations to the Security Process Advisory Task Force (SPATF)and successor group. There may be representation on TWG from each Area Security CoordinationCenter (ASC) as determined by the NERC Regions. Subgroups may be formed by the TWG (whichitself is a permanent body) to effectively meet this scope with representation from TWG and othersources. NERC Staff will facilitate the group.

DUTIES

1. Determine system requirements with the ISN Data Exchange Working Group (DEWG) tosupport the telecommunications required by the ISN.

2. Develop the network specifications and lower layer transport profiles (OSI, TCP/IP).3. Develop network architecture including router or other connectivity requirements, with

consideration to integrating existing networks. Determine network management requirements.4. Develop the RFP for a telecommunications vendor to supply a frame relay communications

system.5. Conduct the bid process and recommend the vendor.6. Develop the RFP for network on-line management, with responsibility for:

a) Review network performanceb) Receive requests for and recommend bandwidth allocationc) Determine the correct bandwidthsd) Manage routing.

7. Establish procedures to assure network security.8. Review other communications schemes over time and recommend changes as warranted.9. Perform other duties as required or assigned

NERC ISN DATA EXCHANGE WORKING GROUPSCOPEDECEMBER 1996

NERC ISN

The NERC Interregional Security Network (ISN) provides timely and accurate data and information toassist those charged with assuring secure interconnected transmission system operation.

PURPOSE

The Data Exchange Working Group (DEWG) develops data management and transfer specificationsfor the ISN, oversees planning, implementation, and use of the ISN, monitors functional performance ofthe ISN, and recommends changes to the ISN.

The Security Process Implementation Timeline shows the ISN in place for initial data input by 01 June1997; the Working Group will work to meet this objective.

REPORTING AND COMPOSITION

The DEWG reports and makes recommendations to the Security Process Advisory Task Force(SPATF) and successor group. There may be representation on DEWG from each Area SecurityCoordination Center (ASC) as determined by the NERC Regions. Subgroups may be formed (withrepresentation from DEWG and other sources) by the DEWG (which itself is a permanent body) toeffectively meet this scope. EPRI may be represented on DEWG and NERC Staff will facilitate thegroup.

DUTIES

1. Ascertain from each Area Security Coordinator (ASC) and other organizations which; require datafrom the ISN, the data requirements to perform their security roles.

2. Interface with the Transaction Reservation and Scheduling System Definition Team to support theirrole.

3. Manage ISN data including database dictionary and standardized global naming of power systemdata.

4. Recommend policies pertaining to the quality and timeliness of ISN data to meet the agreed uponsecurity application needs.

5. Develop and coordinate the ICCP implementation.6. Coordinate development of applications to be applied to the ISN.7. Oversee ISN applications and data maintenance.

Agenda Item 4.a.iiOC MeetingMarch 11 12, 1997

-DRAFT-SCOPE STATEMENT

Group: Disturbance Analysis Working Group (DAWG)

Reports to: Operating Committee (OC) (primary) and Engineering Committee (EC)

Purpose: 1. Review significant disturbances, demand reductions, public appeals, and unusualoccurrences on the bulk electric systems for compliance with NERC Planning andOperating Policies.

2. Provide the EC and OC with recommended revisions to the Planning Policies andOperating Policies as a result of these reviews.

3. Prepare the annual NERC System Disturbances report for publication with summariesof the disturbances to the EC for review and to the OC for review and approval.

4. Participate in preparation of Regional System Disturbances reports, as necessary.

5. Review recommendations made in NERC and Regional System Disturbances reportsto ensure the recommendations are addressed in a timely fashion.

6. Monitor system disturbance reporting by the Regions to ensure that they follow therequirements as specified in Appendix 5F Reporting Requirements for MajorElectric System Emergencies and report these disturbances on the NERC Internet website and NERC Bulletin Board System.

Membership: One system operator from each Region; three planning engineers, at least one of which isknowledgeable in system protection design; additional members to ensure at least onerepresentative from Canada and one representative from each segment of the electricsupply industry, if they wish to participate; and a NERC staff coordinator.

Meetings: One meeting per year, held the day before the fall EC/OC meetings; others as needed.

Quarterly conference calls: review and assign disturbances to Working Group membersfor analysis in the annual NERC System Disturbances report. Discuss other items toinclude in report. Monitor the reporting of disturbances to NERC and the Regions.

Fall EC/OC meetings: continue review and assignments, and outline preparation of theannual NERC System Disturbances report.

Winter EC/OC meetings: Present the draft NERC System Disturbances report to the EC forreview and the OC for review and approval.

April 15: Publish annual NERC System Disturbances report.

SCOPE STATEMENT

Group: Disturbance Analysis Working Group (DAWG)

Reports to: Operating Committee (primary) and Engineering Committee

Guides: none

Purpose: 1. Review significant disturbances, demand reductions, and unusual occurrences on thebulk electric system.

2. Provide Operating Committee and Engineering Committee with suggested revisions tothe Operating Guides and Planning Guides as a result of these reviews.

3. Prepare annual System Disturbances Report for publication with summaries to theOperating Committee and Board of Trustees.

Membership: Six members. Four system operators; two engineers, one of which is knowledgeable in systemprotection design. Members should be from different Regions.

Meetings: Three. Each held the day before the August, November, and February OperatingCommittee meetings.

Milestones: August meeting: Review and assign disturbances to working group members for analysisin annual report. Discuss other items to include in report.

November meeting: continue review and assignments.

February: All analyses drafts and diagrams due to working group members and NERC staff.

February meeting: Review and edit drafts.

April 15: Final drafts due to working group and NERC staff.

May 15: NERC staff sends report to Operating Committee for approval at its June meeting.

May 23, 1996

Agenda Item 4.a.iiiOC MeetingMarch 11 12, 1997

NERC SECURITY PROCESS SUPPORT SYSTEM TASK FORCE SCOPE(Revised 2-25-97)

INTRODUCTION

The NERC Security Process Advisory Task Force (SPATF) administered the initial development of theSecurity Process, described in the Security Process Task Force Report of February 1996. Two keycomponents of the Security Process are the Transaction Information System (TIS) and the InterchangeDistribution Calculator (IDC). The TIS provides for “tagging” of all interchange transactions with the source,intermediary entities, and destination information needed by the Security Coordinators to administer theSecurity Process; and the IDC provides the Security Coordinators with a tool to determine whichtransactions are impacting the loading on critical transmission facilities. The Security Process SupportSystem Task Force (SPSSTF) will oversee the development, implementation, and integration of the TIS andIDC with other components of system control and the Security Process.

In its report of December 1996, the NERC Transmission Reservation and Scheduling Task Force (TRSTF)conceptualized a comprehensive process for the orderly reservation and scheduling of transmission service.The Transmission Reservation and Scheduling (TRS) process envisioned by the TRSTF is intended tofacilitate the reliable reservation and scheduling of transmission service by Transmission Customers (TCs)in accordance with the actual flows that would result on the transmission system from proposed interchangetransactions. Matching interchange schedules and their associated transmission service with their resultantsystem power flows would help to ensure the reliability of the transmission system by reducing the need forTransmission Providers to invoke Regional Security Processes. Those processes often require theinterruption of commercial activity, in order to preserve the reliability of the transmission network. Both theTIS and the IDC are also prerequisite parts of the TRS. At its January 1997 meeting, the NERC Board ofTrustees endorsed proceeding with a “proof of concept” prototype of the TRS process. The SPSSTF willdesign, develop, and test the prototype TRS system envisioned by the TRSTF.

It should be noted that both the TIS and the IDC are key integral components of the Security Process. Theirdevelopment and implementation must proceed for the success of the Security Process, regardless of thesuccess, failure, or progress of the TRS prototype.

SCOPE DETAILS

General• Review and present recommended changes to this scope.• Establish and maintain strong liaison relationships for coordination with associated Subcommittees,

Working Groups, and Task Forces involved in the Transmission Market and Security Process Initiatives.

TIS and IDC Work• Detail the requisite ties for TIS and IDC with and between other reliability systems such as Energy

Management Systems and the Interregional Security Network (ISN), and potential ties to the OpenAccess Same-time Information Network (OASIS).

• Make the TIS and IDC vendor selection.• Work with the selected vendor on TIS and IDC implementation.

TRS Prototype Work• Prepare detailed descriptions of the overall TRS process architecture components of the prototype,

including reservation and scheduling “algorithms”, and its integration with the TIS and IDC.• Develop an RFP for the approved TRS prototype approach.• Make the TRS prototype vendor selection.• Work with the selected vendor on the TRS prototype development and testing.

RESOURCES

• NERC Staff will facilitate.• EPRI will provide assistance.• The SPSSTF will coordinate with and maintain liaisons to:

• The Security Coordinator Subcommittee (SCS) and its ISN Telecommunications and Data ExchangeWorking Groups (TWG and DEWG)

• The Interconnected Operations Subcommittee (IOS)• The Multiregional Modeling Working Group (MMWG)• The ATC Working Group (ATCWG)• The Industry’s “What’s Next” Working Group• The Industry’s “How” Working Group

• Representatives of the SPATF, or successor group, and the TRSTF will assist the SPSSTF in becomingfamiliar with the reports.

• The SPSSTF will appoint other groups to work with it in elaboration of process details as necessary.

DETAILS

• The SPSSTF will report to the Joint NERC Engineering and Operating Committees• The SPSSTF’s composition will include at least one representative from each NERC Region, including

representation from each industry segment, with individual focus on the following skills: operations,marketing, information systems, telecommunications.

Agenda Item 4bOC MeetingMarch 11612, 1997

Operating Committee Organization andProceduresSubsectionsOperating Committee Organization1. Mission2. Representation3. Observers4. Officers5. Executive Committee6. Steering CommitteeOperating Committee Procedures1. Meetings2. Voting3. Selection of Officers4. Formation of Subcommittees, Working Groups, and Task Forces5. Process for Handling Modifications and Additions to NERC Operating Policies6. Parliamentary Process

The North American Electric Reliability Council s (NERC) mission is topromote the reliability of the electricity supply for North America. It doesthis by reviewing the past for lessons learned, monitoring the present forcompliance with Policies and Standards, and assessing the futurereliability of the bulk electric systems.

NERC is a not-for-profit corporation whose “owners” are the Regional Councils. The members of these Regional Councils and the one affiliate Council areindividual electric systems from all ownership segments of the electricity supplyindustry & investor-owned, federal, rural electric cooperatives, state, municipal,and provincial utilities, independent power producers, and power marketers. These entities account for virtually all the electricity supplied in the United States,Canada, and the northern portion of Baja California, Mexico.

The activities of NERC are directed by its Board of Trustees. The Board iscomprised of about 30 electricity supply industry executives including the Board sofficers, two representatives from each Regional Council, and others as needed toensure at least two representatives from Canada and at least two representativesfrom each electricity supply industry ownership segment.

Meetings of the Board are attended by observers from the U.S. Department of En-ergy, the Federal Energy Regulatory Commission, the National Energy Board ofCanada, the National Association of Regulatory Utility Commissioners, andseveral industry organizations & Edison Electric Institute, American Public PowerAssociation, National Rural Electric Cooperative Association, Electric PowerResearch Institute, Canadian Electricity Association, and the Electric GenerationAssociation and National Independent Energy Producers.

The technical activities of NERC are carried out by its Engineering Committeeand Operating Committee. The Committees and their subgroups are comprised of

Operating Committee Organization and ProceduresOrganization

Draft: February 24, 1997 %%2%% December 3, 1996

managerial and technical representatives from the Regional Councils and fromelectric industry ownership segments, as appropriate.

This document addresses the organizational structure of NERC s OperatingCommittee. It updates and supersedes the Operating Committee portion ofNERC s January 1984 Organizational Structure of Technical Committeesdocument. This update was necessary to accommodate the Operating Committeeexpanded membership policy and other changes related to the OperatingCommittee mission, selection of officers, subgroups, and meetings.

Operating Committee Organization

A. Mission

The Operating Committee:

1. Actively promotes the reliable operation of the interconnected electricsystems in the United States, and Canada, and Northern Baja California,Mexico.

2. Establishes Policies and Standards for interconnected systems operation,

3. Monitors compliance with the established Policies, and

4. Provides a forum for the coordination of dealing with interconnectedsystems operation issues.

B. Representation

1. Regional Council Representation. Each Regional Council shallhave at least appoint two representatives to serve on the OperatingCommittee. Certain councils, because of geographical size ormagnitude of demand, may, with the concurrence of the OperatingCommittee, haveappoint more than two representatives. RegionalCouncil representation as of December 1, 1996 is shown on thefollowing table:

Region Number of OCRepresentatives

ECAR 3

ERCOT 2

FRCC 2

MAAC 2



Organization

MAIN 2

MAPP 2

NPCC 3

SERC 3

SPP 2

WSCC 4

2. Industry Segment Representation. The Operating Committee shallinclude at least two representatives from Canada plus at least tworepresentatives from each segment of the electric industry

2.1. U.S. federal

2.2. investor-owned

2.3. rural electric cooperative

2.4. state/municipal

2.5. independent power producer, and

2.6. independent (non-affiliated) power marketer.

3. Filling industry segment vacancies. The following procedure will beused to fill industry segment vacancies:

2.1.3.1. Nominations from Regional Councils. Each RegionalCouncil will provide a list of nominees selected from theirmembership who they feel have the competencies that wouldenhance the effectiveness of the Operating Committee inattaining its mission.

2.2.3.2. Slate determined by Chair. The Committee Chair shallpropose a slate of candidates from this list. In selectingcandidates, the Committee Chair will take into consideration thediversities of geography, experience, and viewpoint.

2.3.3.3. Committee selects from slate. The Committee shall selectrepresentatives from this slate to fill such vacancies for two-yearterms as may be required to ensure adequate representation. Members so selected are provided membership with the intentthat they provide an operating point of view from that segment ofthe industry.



Organization

2.1.1.3.3.1. Segment representation term. New segmentrepresentatives shall normally serve two-year terms. However, their service shall end upon change ofemployment to a position outside the industry segmentfrom and for which they were selected.

2.1.2.3.3.2. Authorization to replace representative. Anunfulfilled term shall be served by a replacementindustry segment representative, if needed. In this case,in the interest of time, the committee Chair shall followthe procedures in sections 23.1 and 23.2 above, and maythen perform the final selection.

4. Segment representation review. The Chair shall review industrysegment representation whenever a Committee member s term ends, andselect a replacement, if needed, as explained in Section 23 above. (Asegment representative need not be replaced if that segment is alreadyrepresented by a Regional Council member.)

4.1. The Chair should not allow two or more consecutive meetings topass before filling the absent industry segment representativeposition.

C. Observers

1. Designating observers. The Operating Committee shall:

1.1. Designate Observers to its Committee who arerepresentatives of the United States government and thegovernment of Canada, and

1.2. Invite other U.S. and Canadian federal agencies or national orinternational organizations, whose interests and activities areconcerned with interconnected systems operation, to designate anindividual to observe the meetings of the Committee upon thedetermination by the officers of the Committee that such actionwould enhance the effectiveness of the Committee in attaining itsmission.

2. Observer term. The term of each Observer shall be two years. SuchObservers may be permitted to participate in the meetings of theOperating Committee and those Committee subgroups the officers of theCommittee may deem appropriate, but the Observer shall not have thepower to vote.



Organization

D. Officers

1. Officers. The officers of the Committee shall include a Chair, ViceChair, Secretary, and immediate past Chair. Officers are neither RegionalCouncil representatives nor industry segment representatives whileserving as officers. The Chair is a member of the Committee.

2. Terms. The term of office is two years, and the normal progression isfrom Vice Chair to Chair. The Vice Chair succeeds to the chairmanshipwhen the chair is left vacant for any reason. Changes of officers takeplace at the beginning of the calendar year or whenever a successor isappointed.

3. Selection. Refer to Section 4.C., $Selection of Officers.#

4. Duties of Operating Committee Officers

4.1. Committee Chair

4.1.1. Provide general supervision of Committee activities, andact as spokesman for the Committee. Provide leadershipand set the agenda of Committee activities.

4.1.2. Administer the Committee meeting agendas and presideat the meetings

4.1.3. Serve as a member of the Technical Steering Committee.

4.1.4. Represent the Committee to the Board of Trustees andother forums as appropriate.

4.1.5. Execute decisions by the Board of Trustees and performother duties as directed by the Board.

4.1.6. Establish such subcommittees, working groups, or taskforces as may be directed by the Committee.

4.1.7. Notify in writing all newly appointed representatives toexisting or new subcommittees, working groups, or taskforces of their appointment.

4.1.8. Propose a slate of candidates to fill industry segmentrepresentative vacancies and appoint Committeeobservers, as appropriate.

4.1.9. Appoint a three-member Nominating Committee at theJuly regular Summer meeting of the second year of theChair s term.

Makes the Chaira member of theCommittee

Superfluous.



Organization

4.2. Committee Vice Chair

4.2.1. Perform the duties of the Chair in his or her absence.

4.2.2. Assist the Chair as called upon.

4.2.3. Serve as a member of the Technical Steering Committee.

4.2.4. Attend meetings of the Board of Trustees.

4.2.5. Serve as chair of the OC Steering Committee andperform duties as prescribed in the OCSC ScopeStatement.

4.3. Committee Past Chair

4.3.1. Assist the Chair as called upon.

4.3.2. Serve as a non-voting member of the OperatingCommittee.

4.3.3. Serve on OC Steering Committee.

4.4. Committee Secretary

4.4.1. Prepare the minutes of the Committee meetings.

4.4.2. Maintain the Committee records.

4.4.3. Assist the Chair and Vice Chair as called upon.

E. Operating Committee Executive Committee

1. Executive Committee members. The Operating Committee ExecutiveCommittee shall consist of the Chair, Vice Chair, Secretary, and PastChair, and subcommittee chairmen.

1.1. Duties. The Executive Committee will assist the Chair in:

1.1.1. Coordinating Subcommittee activities1.1.2. Preparing the OC meeting agenda1.1.3. Suggesting items for OC review1.1.4. Responding to urgent matters1.1.5. Preparing reports to the Board of Trustees

2. Authority. The Executive Committee may exercise all the powers of theCommittee between meetings of the Committees. Any action taken by theExecutive Committee will be submitted for ratification at the nextmeeting of the full Operating Committee.

Revises structureof ExecutiveCommittee.



Organization

3. Meetings. The Chair may call for a meeting of the Executive Committeeat any time. The Chair may also invite others to meetings of theExecutive Committee as needed.

F. Operating Committee Steering Committee

1.Operating Committee Steering Committee Membership. The OCSC shallconsist of one Operating Committee representative from each Region,plus the OC Chair, Vice-Chair (who will chair this Committee),immediate past Chair (if available), and Secretary. Subcommitteechairmen that are not Steering Committee members will be invited asneeded.

1.1.Duties. The OC Steering Committee will:

1.1.1.Identify concerns and recommend Operating Committeeactivities that enhance interconnected systems operation

1.1.2.Identify and assist in formulating issues to provide clearlydelineated direction to the OC subgroups.

1.1.3.Assist the Chair in setting a focused agenda.

1.1.4.Assess subgroup progress and recommendations to the OC.

1.1.5.Administer subgroup membership.

1.1.6.Serve as the initial contacts for reporting on specialoperating events.1 (Refer to "Reporting on SpecialEvents" in the Procedures section of the OperatingCommittee Handbook).

1.2.Voting. The OC Steering Committee will reach agreement byconsensus.

1.3.Meetings. The OC Steering Committee shall meet Immediatelybefore and after each OC meeting. The Operating CommitteeChair or Vice Chair may call for special meetings of the OCSteering Committee as needed.

1The OCSC will be joined by the chair of the Disturbance Analysis

Working Group plus the Engineering Committee vice chair.

Remove OCSteeringCommittee



Procedures

Operating Committee Procedures

A. Meetings

1. Meetings. The Operating Committee shall hold three regular meetingseach year, concurrently with the Engineering Committee, with a provisionfor joint meetings of the two committees as required.

1.1. Special meetings. The Operating Committee Chair may call forspecial meetings of the Committee as needed.

2. Attendance. Attendance at the Operating Committee meetings is limitedto those in the NERC Committee structure, Regional Council staff, NERCstaff, official Observers, and those invited by the Chairmen.

3. Substitutes and proxies. A Region or industry segment representativemay send a substitute representative to attend in place of its regularrepresentative. Substitutes are entitled to participate in meetingdiscussions. A substitute is entitled to vote only if the Region submits aproxy, over the signature of the Committee member being represented, tothe Committee Chair.

B. Voting

1. Quorum. The quorum necessary to transact business at meetings of theCommittees shall be a majority of the Committee voting representativesand proxies entitled to be present.

2. 2/3 majority to carry an issue. In the Operating Committee, an issue amotion will be carried by at least a 2/3 majority of the votes cast2 by therepresentatives at any meeting in which a quorum is present.

2.1. Officers. The Chair, Vice Chair, Secretary, and Past Chair arenot entitled to vote. The Chair may vote in those instances whenthe Chair’s vote would affect the outcome.

2.2. Voting by mail. The Committee may vote by mail (including e-mail) on any motion that has been Postponed Until A CertainTimeballots in order to complete business in a timely fashion.

2.3. Operating Policies. In the case of voting on the adoption ofamended or new Operating Policies, the affirmative vote of atleast two-thirds of the Regions is required.

2 The number of votes cast equals the number of affirmative votes plus the number ofnegative votes.

Calculationof majority.

Allowing theChair to vote incertaininstances.

Voting by mail or e-mail.



Procedures

C. Selection of Officers

1. Chair and Vice Chair. The Chair and Vice Chair of the OperatingCommittee are appointed by the Chair of the Board of Trustees at theBoard s September meeting from a slate of candidates recommended bythe CommitteeV Nominating Committee and approved by the OperatingCommittee.

2. Secretary. A Committee Secretary will be appointed by the CommitteeV

officers from the NERC staff and will not have the power to vote.

D. Formation of Subcommittees, Working Groups, andTask Forces

1. Subcommittees. The Operating Committee may establish subcommitteesto which certain of the CommitteeV broadly defined continuing functionsmay be assigned. The Operating Committee will draft the initial scopestatement for the Subcommittee. Upon the formation of a subcommittee, awritten scope must be submitted to the Board of Trustees for approval. The subcommittee chair (and vice chair, if appropriate) will be appointedfor a two-year term by the Operating Committee Chair.

2. Working Groups. The Operating Committee or subcommittee may alsodelegate specific continuing functions to a working group. A workinggroup has a more narrow scope than a Subcommittee. Upon theformation of a working group, a written scope must be submitted to theparent Committee for approval. The Operating Committee will draft theinitial scope for the working group. The working group chair (or vicechair, if appropriate) will be appointed for a specific term (generally twoyears) by the Operating Committee Chair.

3. Task Forces. Should the Operating Committee or subcommittee desireto form a group to address a specific issue, that group will be known as atask force. Normally, a task force should be constituted for no more thanone year. The formation of a task force, development of its scope, andappointment and term of its chair (and vice Chair, if appropriate) arehandled in the same manner as for working groups.

4. Forms of representation. There are two basic forms of representationon a subcommittee, working group, or task force:

4.1. Regional representation. Where Regional representation isnecessary, one representative will be appointed by each RegionalCouncil. Should the subcommittee, working group, or task forceso constituted not have at least one representative from Canadaand each segment of the industry as defined in Section II. Babove, the Chair of the parent Committee or subcommittee towhich the subgroup reports will invite that segment notrepresented to appoint a representative. Regional nominations ofindustry segment representatives as specified in Sections 3.1 and

Must use nominatingprocedures to selectindustry segmentreps for Subcom-mittees. Not neededfor working groupsor task forces.

The parent group shoulddraft the initial scope forits subgroup. – DMB



Procedures

3.2 are required for selection of industry segment representativesfor subcommittees.

4.2. Individual expertise. Where representation is based solely onindividual expertise as it relates to the mission of thesubcommittee, working group, or task force, without therequirement for Regional and electric industry segmentrepresentation, appointments will be made by the chair of theparent Committee or subcommittee to which the subgroupreports, after coordinating with the chair of the proposedsubgroup and appropriate NERC and Regional Council staffs.

5. Sunset review. At least every two years, every subcommittee, workinggroup, and task force must submit, to the Operating Committee, arecommendation to continue, change its scope, or dissolve.

E. Process for Handling Modifications & Additions toNERC Operating Policies

1. Background

This section explains how NERC Operating Policies aredeveloped, modified, and implemented.

The NERC Operating Committee has been working for thelast several years to make the NERC Operating Policies(formerly called the NERC Operating Guides) more usableand understandable. This effort has resulted in (1)complete reformatting of the Operating Guides intoOperating Policies, (2) development of a ComplianceReview procedure to insure that the Operating Policies areadhered to by NERC Control Areas, and (3)implementation of a Compliance Resolution process tofacilitate resolution of those instances in which non-compliance with NERC Operating Policies has occurred.

The Operating Committee adopted the restructuredOperating Policies in August 1995. There is, however, acontinuing need to revise the Operating Policies as changesin the operating environment occur (and they are certainthe occur in today s open access environment). Thisdocument explains the procedures for keeping these Policies up-to-date.

2. Initiation of Modifications and Additions . Changes to the OperatingPolicies may be offered by anyone with a legitimate interest in powersystem reliability. Likely contributors to the Policies are:

& Transmission owning utilities& Generation owning utilities

Change proposed.

Subcommitteedevelops draft

Policy

Regions summarizecomments and send

to Subcommittee

Subcommitteeincorporates

Regions’ commentsand sends draft

Policy to OC

OC approves draftPolicy for Regional

vote

Regions vote within30 days of receipt of

draft Policy

Policy implementedon effective date.

OC follows up tocheck compliance



Procedures

& Transmission dependent utilities& Independent power producers& Power marketers and power brokers& Customers, both retail and wholesale for resale

Proposals for modifications and additions should be made in writing tothe Secretary of the NERC Operating Committee. The Secretary willthen refer the proposal to the appropriate Subcommittee(s) for review andanalysis.

2. Subcommittee Review and Analysis. The subcommittee to which themodification or addition is assigned will review the suggestion, and if itbelieves the recommendation has merit, will prepare a suggested Policyrevision for the Operating CommitteeV consideration.

2.1. Compliance. The subcommittee must consider not only themerits of the proposal but also how compliance with the revisedPolicy will be measured. The NERC control areas mustunderstand how they will be judged for compliance prior tovoting on the Policy revision. If the revision results in a newStandard, then the Subcommittee must recommend a specificmethod to measure compliance (for example, a periodic survey)so that all control areas and Security Coordinators will be awareof how they will be evaluated if the proposed modification oraddition is approved.

If the proposal produces a Requirement, then there is noquantifiable (measurable) compliance level. However, thesubcommittee must still indicate how compliance is to bedetermined.

2.2. Effective date. The Subcommittee must establish an effectivedate for each and every provision in the proposed modification. The effective date is the date which the provision is to beimplemented. All affected entities are expected to comply withthe Policy at that time.

2.3. Vote breakdown. The Subcommittee will also determine thestructure for the Regional vote, that is, whether the Policy shouldbe voted on in its entirety or in sections. It will recommend thesubdivision of the Policies if the vote is to be taken on individualprovisions. Regions will be permitted to comment on the votingstructure as well as the content of the Policy revision. Theapproval of the Operating Committee to send a Policy revisionout for vote also constitutes approval of the voting structure.

3. Region Review and Comment Period. Once the subcommittee hasdetermined that the proposal should be considered for inclusion in theNERC Polices and has satisfied with the form and content of the languageto be voted on, the draft Policy will be submitted to the Regions for



Procedures

review. The Policies will be provided via the NERC BBS and InternetWeb site only. Hard copy will only be provided on an exception basis. Reply comments will be returned to the NERC Subcommittee by thesame electronic means. Regions will have, at most, 60 days in which tosubmit their comments. The comment period might be shorter if themodification simply adopts an already agreed to operating policy.

4. Operating Policy Finalization. The subcommittee will review thecomments received from the Regions and will make whatevermodifications to the Policies that it deems appropriate. The final draftwill then be submitted to the Operating Committee for approval to send tothe Regions for vote, again via the NERC BBS and Internet Web site.

5. Region Voting. Regions will have 30 days from the date of publicationon the Internet in which to vote. Voting will be done electronically by e-mail to the OC Secretary.

5.1. Regions that vote against a proposed Policy revision shall explaintheir negative vote and, if possible, offer specific changes to theproposal that would be acceptable. There may be some instanceswhere the Policy issue is such that Regions can only agree withthe proposal or disagree with it. There may be no acceptablecompromise.

6. Policy Implementation. The NERC Staff will notify all affected partiesof the ballot results via e-mail and the NERC Internet Web site. ThePolicies will take effect on the date specified within the Policy.

6.1. The NERC Operating Committee must follow up to ensure thatRegions and control areas are implementing the approvedPolicies. Measurements to evaluate compliance, whereapplicable, should be taken at the earliest possible time toestablish a benchmark for system reliability. Only then can theprogram for dealing with non-compliance be initiated.

F. Parliamentary Procedure

The latest edition of Robert s Rules of Order Newly Revised, 1990 edition, shallapply in all cases to which they are applicable in the absence of specificprovisions in this document.

Draft 02/27/97 8:39 AM

Re: NERC O&P Document Page 1

Agenda Item 4cOC MeetingMarch 11 12, 1997

NERC Operating Standards and Policies

Proposed Amendments to Organization and Procedures

To Ensure Due Process and Appeals

Submitted to the NERC Operating Committee byKurt J. Conger, Director of Policy Analysis

American Public Power Association

Consistent with the NERC Board of Trustees Strategic Initiative to develop engineering and operating

standards, the operating committee proposed a document, Operating Committee Organization and

Procedures ("O&P Document"), at its December 3, 1996, meeting. That document was approved by the

NERC Board of Trustees at its January meeting.1 At the December 3, 1996, Operating Committee meeting,

the APPA observer commented that there appeared to be deficiencies in the O&P Document that omitted

due process requirements commonly found in other standards setting processes. In particular, the O&P

Document lacks an appeals process. APPA was asked to elaborate on this concern for consideration by the

Operating Committee at its next meeting.

Draft 02/27/97 8:39 AM


1. Balance: no single economic interest dominates

See discussion below under ANSI procedure 1.2.2. for a description of balance in representation

of interests in standards development.

2. Standards approved by consensus

For purposes of voting, the author defines consensus as "much more than a simple majority, but

not necessarily unanimity." But equally important is the method of forming a legitimate

consensus body. ANSI proposes three methods for development of consensus.4 The three

methods are: 1) accredited organization method, 2) accredited standards committee method, and

3) accredited canvass method.

3. Formal procedures for handling negative votes"negatives"

• "No" votes cast without explanation are treated as abstentions.

• Negatives are reviewed by subcommittee. They are typically withdrawn, if changes are

made to reflect the objection, or can be rejected as "nonpersuasive" by vote with explanation

by the reviewing committee.

4. Due Process:

• Written Procedures

• Meetings open to the public. Participation by materially affected parties is not limited

• Membership is open subject to requirements for balance

• Public announcement of proposed standards

• Written records of decisions are made

There is increasing emphasis on establishing a complete written record to justify the

decisions reached and to disclose the consideration that was given to comments and

negatives.

• Standardization documents are not privileged from disclosure.

• Rhgh>of Appeal. Appeals are made to the standards organization to determine:

whether procedures were followed,

whether all points of view were considered adequately, and

whether all negatives were handled appropriately.

4 ANSI. Procedures for the Development and Coordination of American National Standards. Annex E -

The Three Methods for Consensus Development.

Draft 02/27/97 8:39 AM


NERC Process for Handling Modifications & Additions to Operating Policies v.ANSI Due Process Requirements

The American National Standards Institute (ANSI) prescribes procedures and requirements for

development of consensus based standards. These were compared with the NERC O&P

Document to determine areas of deficiency. The table below describes the results of this

comparison.

ANSI Requirement NERC Operating Committee Organization andProcedures Reference

1.2.1. Openness:"Participation shall be open to allpersons who are directly and materiallyaffected by the activity in question.""There shall be no undue financialbarriers to participation.""Timely notice of any action[s]…to alldirectly affected and materially affectedinterests."

Organization: Part B. Representation; Part C.Observers (limited by non-voting status)Procedures: Parts E.2.1., E.2.2., E.3., E.5.General: Use of the Internet helps facilitatenotification and participation by reducing costsassociated with participation, however, a morecomplete canvass list should be developed to ensurethat notices are provided to all affected interests.

1.2.2. Balance: "The standardsdevelopment process should have abalance of interests and shall not bedominated by any single interestcategory."

Organization: Part B. Investor-owned segmentconstitutes a majority of the membership.Procedures: Part B. Until balance of interests can beachieved, 2/3 voting ratio does not protect minorityinterests.

1.2.3. Interest Categories: "The interestcategories…are a function of the natureof the standards being developed.""In defining the interest categories …consideration shall be given to at leastthe following: 1. Producer, 2. User, 3.General interest.""Appropriate, representative user viewsshall be actively sought and fullyconsidered…"

Organization: Part B.2. Industry segmentrepresentation based on ownership needs furtherseparation between transmission service providers(producer category) and transmission servicecustomers (user category). The general interestcategory is not represented by existing NERCsegments. Possible representation may come fromregulatory agencies, consumer groups, or tradeassociations that represent manufacturers ofproducts that depend on reliable electric service.

1.2.4. Written Procedures: "shall governthe methods used for standardsdevelopment and shall be available toany interested person."

While not specifically provided for in the NERCdocument, it is assumed that the procedures willbecome part of the Operating Policies documents.

1.2.5. Appeals: "The written proceduresshall contain an identifiable, realistic,and readily available appealsmechanism for the impartial handlingof substantive and proceduralcomplaints regarding any action orinaction."

While NERC contemplates a dispute resolutionprocess, a properly defined appeals process is notincorporated in the operating procedures. See thediscussion below for recommendations.

1.2.6. Notification of standardsdevelopment: "…activity shall beannounced in suitable media asappropriate to demonstrate provision ofopportunity for participation by alldirectly affected and materially affectedpersons."

Procedures: E.5. and E.6.See ANSI 1.2.1. above. Also see ANSI Guidelinesfor the Electronic Distribution of Standards RelatedInformation. While electronic distribution issatisfactory for many affected interests, subscriptionfee-based services are needed to provide hardcopyof documents for those who desire printed media.

Draft 02/27/97 8:39 AM


1.2.7. Consideration of views andobjections: "Prompt consideration shallbe given to the written views andobjections of all participants…"

Procedures: E.6. The NERC procedure fails toprovide acceptable guidelines for documenting bothresolved and unresolved objections.

1.2.8. International Standards:"Developers of American NationalStandards shall take internationalstandards into consideration…"

Organization: B.2. Canadian interests are included.Is there need for consideration of reliabilitystandards that are outside the bounds of the NorthAmerican interconnection?

1.2.9. Substantive change: "a change …that directly and materially affects theuse of the standard."

Add to Procedures and explicit provision that: "Anysubstantive changes will be noticed for publicreview and comment."

1.2.10. Commercial terms andconditions: "business relations … shallnot be included in standards."

No conflict identified, but an explicit provisionshould be added to the Procedures.

1.2.11. ANSI patent policy: specialprovisions apply to the use of patentedinventions in standards.

Not applicable to NERC at this time.

1.2.12. Consideration of standardsproposals: "Prompt consideration shallbe given to proposals made fordeveloping new standards, or revisingor withdrawing existing standards."

Procedures: E.5. While the NERC OperatingCommittee requires interests to promptly reviewand comment on proposed standards, there is noexplicit obligation of the committee to promptlyreview and respond to comments and objections.See ANSI, Guide for Accelerating the Developmentof American National Standards. "The primary goalof developing effective standards using due processcannot be sacrificed for speed."

1.2.13. Records: "Records shall beprepared and maintained to provideevidence of compliance with theseprocedures."

No records retention policy is stated in theOperating Committee Organization and Proceduresdocument. Provisions should be made to reRecdobjections and the response by the committee tothose objections.

Right of Appeals

The table above identifies a number of areas where the NERC Operating Committee

Organization and Procedures document needs revisions to ensure due process. In its Section 6 of

its Procedures, ANSI describes the provision of appeals as important for the protection of

directly and materially affected interests and of standards developers. An appeals procedure is a

required part of due process. While dispute resolution can address issues that arise when there is

a disagreement in the application of established standards, dispute resolution (e.g. mediation and

binding arbitration) appropriate for development of standards. Due process and appeals

provisions must be explicitly stated within the Organization and Procedures document and

strictly followed.

Example: IEEE National Electrical Safety Code

The ANSI C2 committee (IEEE National Electrical Safety Code) is an accredited standard that is

developed under procedures that comply with ANSI due process requirements.

Draft 02/27/97 8:39 AM


The procedures for review and revision of the NESC are structured around a regular revision

cycle (currently 5 years) and public opportunities for Tentative Interim Amendments (TIAs)

which can be proposed at any time, or Interpretations, that provide a mechanism for clarifying

existing NESC standards. Section 15 of the NESC Procedures describes the appeals procedure.

Suggested Revisions to the NERC Operating Committee Organization andProcedures Document

At this time two revisions are suggested for the NERC Operating Committee Organization and

Procedures document. First, the addition of an appeals procedure, and secondly, improvements

to the consensus development processes. Other deficiencies, noted in the table above, should be

discussed and resolved by the Operating Committee. In many respects each could be developed

into a written application for appeal of the O&P Document itself.

Appeals Procedure

As an initial draft appeals procedure, the IEEE NESC appeals procedure was adapted to the

context of the NERC O&P Document. The suggested revision requires adding after section F.,

Parliamentary Procedure, a new section G. as follows:

G. Appeals

Directly and materially affected interests who believe they have been or will be adversely

affected by the NERC Operating Policies and Standards shall have the right to appeal

substantive or procedural actions of the Committee.

G.1. Complaint

The appellant shall file a written complaint with the Committee Secretary, within 30 days after

the date of notification of action, or at any time if the appeal is based upon the failure of the

Committee to revise its Operating Policies and Standards in accordance with established

schedules and procedures. The complaint shall state the nature of the objection(s) including any

adverse effects, the section(s) of these Operating Policies and Standards or Committee

Organization and Procedures that are at issue, actions that are at issue, and the specific remedial

action(s) that would satisfy the appellant's concerns. Previous efforts to resolve the objection(s)

and the outcome of each shall be noted.

G.2. Response

Within 30 days after receipt of the complaint, the respondent (Chair or Secretary) shall respond

to the appellant, specifically addressing each allegation of fact in the complaint to the extent of

the respondent's knowledge.

Draft 02/27/97 8:39 AM


G.3. Hearing

If the appellant and the respondent are unable to resolve the written complaint informally in a

manner consistent with these procedures, the Executive Committee shall appoint a panel of at

least three members, naming one as chair, to determine if a hearing should be held. If the appeal

has merit, the Secretary shall schedule a hearing with an appeals panel on a date agreeable to all

participants, giving at least ten working days notice.

G.4. Appeals Panel

The Appeals Panel shall consist of at least three individuals, appointed by the Executive

Committee, who have not been directly involved in the matter in dispute and who will not be

materially or directly affected by any decisions made or to be made in the dispute. A majority of

the member shall be acceptable to the appellant and a majority shall be acceptable to the

respondent. The panel members shall choose a chair from among themselves.

G.5. Conduct of the Hearing

The appellant has the burden of demonstrating adverse effects, improper actions, and efficacy of

the requested remedial actionúThe respondent has the burden of demonstrating that the

Committee and the Secretary took all actions in compliance with these procedures. Each parting

may adduce other pertinent arguments, and members of the Appeals Panel may address

questions to individuals. Robert's Rules of Order (latest edition) shall apply to questions of

parliamentary procedure for the hearing not covered herein.

G.6. Decision

The Appeals Panel shall render its decision in writing within 30 days, stating findings and

conclusions, with reasons therefor, based on a preponderance of the evidence.

G.7. Further Appeal

If the appellant gives notice that further appeal is intended, a full record of the complaint,

response, hearing, and decision shall be submitted by the Secretary to the forum in which further

appeal is requested.

Improved Consensus Development

Because the NERC Operating Policies and Standards affect a well defined group of interests

(electric power industry and consumer), the current standards committee method can work well

to generate consensus based standards, provided that all affected interests have adequate

representation and notification of substantive changes to the Operating Policies and Standards.

There are significant concerns of minority interests concerning committee balance. These

Draft 02/27/97 8:39 AM


concerns need to be addressed. A canvass list approach to determining whether all affected

interests have been notified of ongoing standards action is a necessary part of the process of

resolving this issue.


Manitoba Hydro Generation LossSeptember 5, 1996

At its December 1996 meeting, the NERC Operating Committee heard a presentation from EarleT. Floyde of Manitoba Hydro, regarding their September 5, 1996 generation loss resulting from a tornadodamaging their transmission system. The OC asked MAPP to provide follow-up reports as it analyzesthis event for lessons learned and for the need for revisions to NERC Operating Policies.

Report finalized February 12, 1997

Introduction

Description of The Disturbance

At 0148 on Thursday, September 5, 1996, a tornado crossed the main north-south transmission corridor ofManitoba Hydro. This corridor connects, by HVDC, the hydroelectric generation in north centralManitoba with its load center(s) in the south, primarily Winnipeg. The resulting damage to MHEBtransmission caused all valve groups of the HVDC systems to block by line protection and resulted in aloss of 2020 MW of generation to the Eastern Interconnection.

Systems and Task Force Members who Contributed to this Report

Manitoba Hydro Electric Board (MHEB)Minnkota Power Cooperative (MPC) (reports requested, not received)Minnesota Power and Light Company (MPL)Northern States Power Company (NSP)Otter Tail Power Company (OTP)United Power Association (UPA)

MAPP Ad Hoc Investigation Team Members

Jerry Hagge, Nebraska Public Power DistrictSheldon Berg, Mid-Continent Area Power PoolLarry Larson, Otter Tail Power CompanyAlan Oneal, MidAmerican Energy Company

Cause and Impact

General

The cause of the event was reported to be a tornado, which took down 19 towers on the two affectedHVDC lines. Its immediate result was loss of two HVDC bipoles; Dorsey-Radisson 500KVDCandDorsey-Radisson 450KVDC. The "event" (large negative ACEs and generation shortage) lasted from0148 until nearly 0300, at which time load - generation balance was restored in MHEB and MAPP. Thesystem frequency returned to 60 Hz 53 minutes after the event. MHEB ACE crossed zero at 0305, 77minutes after the beginning of the disturbance.

Load Loss

Load loss was confined to MHEB, which reported a decrease in load of 260 MW due to the outagesinvolved with the storm(s).

Frequency Disturbance Observations

Frequency, at the time of the line loss, dropped to 59.947 Hz, which did not result in load shedding. Thiswas an excursion of approximately 58 mHz from its original value of 60.005.

Other Impacts

MHEB was scheduling exports of 1473 MW prior to the disturbance. When it occurred, MHEB operatorsdelayed in curtailing schedules, apparently due to past experience with HVDC trips in which theynormally were restored to service in a few minutes. Then they seem to have overlooked cutting theexport schedules as they were dealing with the problems due to the tornado. The activities of the MHEBoperations staff are detailed in E. T. Floyde's letter and report of October 1, 1996. MHEB was not a partof the MAPP reserve sharing pool at the time of this event. By 0230, MHEB had, by their report,curtailed all exports. The largest of these was an 800 MW scheduled delivery to Northern States Power.At the same time, MHEB was arranging imports from Saskpower, Ontario Hydro, and Minnkota PowerCooperative. These imports totaled 350 MW by HE 0400. NSP, OTP, UPA, and MPL all receiveregulation service from MHEB. It appears that MHEB curtailed such service at 0152, which was a properaction.

The event initiated a request from the chair of the MAPP Operating Committee for reports from allaffected companies; MHEB, MPC, MPL, NSP, OTP, and UPA. Concurrently, an Area Interchange Error(AIE) survey was requested by the MAPP survey coordinator.

MHEB system condition returned to "green" on September 10, when half the DC system was restored.Following is information on MHEB facility returns:

Ashern-Rosser 230kV 9/6Rosser-Portage 115kV 9/6Parkdale-Neepawa 115kV 9/6Dorsey-Radisson pole #1 9/9Dorsey-Radisson pole #2 9/10

Mr. Floyde reported, on behalf of MHEB, to the NERC OC at their December 3-4, 1996 meeting. At thistime, the presentation by MHEB appeared to analyze and set forth corrective measures for MHEB topursue to prevent recurrence of such an incident. However, the OC requested further information from allother affected parties, due to the lack of thorough observation and analysis of guides violated and anabsence of clear statement as to what each party would specifically do to avoid a repeat of such asituation.

Conclusions

General

MAPP (and possibly NERC) needs to define specifically the manner in which a schedule should be terminated in adisturbance situation such as this. While it is common practice to do so, standards should require that an export suchas that of MHEB should be cut immediately (no ramp) and cut as soon as possible prior to the end of the first 10minutes following the loss. MHEB clearly was in violation of NERC policies by not curtailing exports that it couldnot supply, and has so stated. However, as of the time they "passed off" the problem by export curtailment, theactivities of those affected by such curtailment become suspect. NSP shows no appreciable movement of ACE at0230, and has a very large (216 MWh) difference between their hourly AIE and integrated ACE. This indicates thatthe schedule curtailment was masked in some way, either by entry of a miscellaneous tie number to counteract theschedule cut, or incorrect or non-entry of the schedule. Either way, the NSP operator did not correctly enter andtrack scheduled interchange. In their initial letter of response, NSP stated that "the precise manner in which NSPcurtailed the schedules at 02:30 cannot be determined." When asked specifically about the operator's activities, NSPwas advised to at least reveal the results of conversation with the operator on duty. To date, no such revelation hasoccurred. NSP did state that the "schedule from MHEB was ramped across 0230 and not zeroed immediately." Butthe ramp duration was not supplied. The answers to many questions regarding treatment of the MHEB schedulecould have been answered by NSP's supplying their net interchange and deviation from schedule chart(s). Theinvestigation team was informed that NSP did not have the chart available.

If NSP had correctly entered and recognized the MHEB schedule cut, they should have declared a MAPPemergency, which would have allowed MAPP to respond to restore balance within the MAPP reserve-sharinggroup, and respond to the requirements of the B1 and B2 criteria. Reserve sharing does no good if the need for it isnot communicated. No recipient of MHEB energy appears in violation of NERC guides at first blush except NSPand MPL, but useful observations emerge from those respondents who looked into the details. Those observationsfollow.

Company-Specific

MHEBMHEB states in their first report (page 5, B1 and B2 criteria) that "reserves were restored within 3minutes." This is not possible, and raises questions about what the statement means. It is further pointedout that reserves from Saskpower were not called upon, yet it is never stated why. This seems odd, giventhat MHEB was more than 1700 MW deficit during much of HE 0300. MHEB reports an 850 MW pre-disturbance schedule with NSP, while NSP reports 800. MHEB's frequency chart stops recording atapproximately 0200. This raises a question as to why this occurred. Possibly an additional frequencysource should be monitored. The sale to NSP was not cut until approximately 40 minutes after the event.MHEB indicated (page 4 of E.T. Floyde's letter) that all exports were zeroed as of 0230, yet thesubmitted schedule sheets show that the sales to UPA and MPC were not cut until 0300. MHEB's ACEchart does not appear to travel at 3"/hr, but somewhat less.

OTPRegulation cut off at 0152. OTP units did not respond to AGC at this time, and OTP has instituted testingprocedures to make sure it does not recur. MW schedule received from MHEB was cut at 0230, but wasmistakenly entered at the hourly integrated value (27) for the remainder of the hour. OTP dispatchermade misc. interchange adjustments to compensate ACE. This was tracked by EMS logging of changesto the value, and OTP dispatchers have been advised this is not proper practice. Had B1 violations in HE0300.

MPLShow zeroing schedules at 0237 and 0238, while MHEB reported 0230 cancellation for all.Had B1 violations in HE 0300, claim that B2 was met

MPCDid not (as of this writing) submit any reports in response to requests.

UPADid not respond to Wally Ness' request for information, but did respond to the second request.

ACE chart does not track at 3"/hr.

Recommendations

General

MAPP should investigate establishment of policy on schedule curtailment under disturbance conditions. NERC maywant to do the same. System operations personnel at MHEB, MPL, OTP and NSP should review their obligationsunder B1 and B2 criteria. NERC Policy 1E.

Operations personnel in MAPP should be reminded through MAPP-sponsored training the proper and improper useof the "miscellaneous tie" or meter error adjustment. NERC Policy 1 Appendix 1A

Company-Specific

� Manitoba HydroReview scheduling process with NSP to be sure schedules are equal and opposite (the 850 vs. 800 observation).NERC Policy 3ANote frequency chart trace cessation. Review source of frequency to allow continuous recording. NERC Policy 4AReview recommendation for 3"/hr on chart recorders. NERC Policy 1 Appendix 1HReview NERC Policy 5 (Emergency Operations) with system operating personnel.

� Northern States PowerReview NERC Policy 1, Appendix 1H, and keep all required chart records for the required length of time. It wasstated in NSP's October 18 letter to Mr. Shel Berg of MAPP that they did "not have data on schedule values thatmay have been entered during the hour, only at the end of the hour." When asked for the net interchange andinterchange deviation from schedule charts, it was stated that they did not have them. NERC Policy 1 Appendix1HObserve the 3"/hr recommended chart speed. NERC Policy 1 Appendix 1HRemind system dispatch personnel of the need to accurately enter scheduled interchange, and the error of maskinglarge interchange values to ACE. NERC Policy 3ARemind system operating personnel of the requirement to promptly balance generation and interchange schedules toload when in an insufficient generating capacity condition. This applies equally to NSP's participation in the MAPPreserve-sharing group, which has an identical obligation to the interconnection. NERC Policy 5B

� MPCMPC should respond promptly to requests for information from MAPP and NERC. NERC Policy 5F, MAPPOperating General Requirement

� MPLReview the recorded schedule cut times of 0237 and 0238 versus MHEB's of 0230. Scheduled interchange betweentwo control areas should be equal and opposite at all times. NERC Policy 3AMPL should also promptly respond to requests for information from MAPP and NERC. Response received fromMPL to second request February 11, 1997. NERC Policy 5F, MAPP Operating General Requirement

�� OTPAppears to have taken proper action to remedy deficiencies observed.

� UPAUPA should also promptly respond to requests for information from MAPP and NERC. NERC Policy 5F,MAPP Operating General RequirementReview chart speed recommendations. NERC Policy 1 Appendix 1H


WSCC July 2–3 and August 10, 1996 EventsFollow-up

6 Implementation of event report recommendations

WSCC representative Ted Reece will review the status of WSCC’s implementation of therecommendations in its reports on the July 2–3 and August 10, 1996 outages.

Action: Discuss the need for further OC action.

6.a NERC Operating Policy changes

The Subcommittee chairs will address whether any changes are needed to NERC OperatingPolicies as a result of the WSCC event analysis.

Action: Discuss proposed Policy changes.

6.b Compliance Review Process

The Operating Committee established a Policy compliance review process that explains how theCommittee is to review events that question a control area’s compliance with NERC Operating Policies.Past Chairman Eugene P. Byars will discuss the compliance review process with the Committee andrecommend any additional actions that the OC may need to take regarding the WSCC and other events.

Action: Discuss


ERCOT January 28, 1997 High Demand

On January 28, 1997, the ERCOT Interconnection faced an exceptionally high demand thatresulted in operation below 60 Hz (down to 59.976Hz) for some time. James A. Byrd will explain howthe ERCOT ISO handled his event.

Action: Discuss


Inadvertent Interchange: Balances in Western Interconnection

WSCC has not been able to balance its monthly inadvertent account since July 1996. A widerange of causes can be attributed to the problem, including after-the-fact changes to balance figures andturn-over and reorganization of staff at the systems. Grant E. Griffith, WSCC-Northwest Power Poolrepresentative on the Performance Subcommittee, has compiled the attached summary.

Performance Subcommittee Chairman Albert M. DiCaprio will lead a discussion of this item.

Action: Discuss situation and solutions suggested by the Northwest Power Pool (last page of attachedreport).

NORTHWEST POWER POOL26 SW SALMON STREET, SUITE 400

PORTLAND, OREGON 97204PHONE: 503-464-2801

FAX: 503-464-2819

DATE: February 17, 1997

TO: Albert M. DiCaprioNERC Performance Subcommittee Chair

FROM: Grant E. Griffith

SUBJECT: Western Interconnection Inadvertent Status

Utility July August Sept. Oct. Nov. Dec.

CA-NVPG&ELDWPSCEWALCNPCBAJA X X X X X XSDGE X X X X X X

NWPPBCHA X X X X XBPACHPD X X X X X XDOPD X X X X X XGCPD X X X X X XIPC X X X X XMPC X X X X X XPAC X X X X X XPGE X X X X X XPSE X X X X X XSCL X X X X X XSRP X X X X X XTCL X X X X X XTAUC X X X X X XWWPC X X X X X X

X - Have received Inadvertent summary.

The first description is of how inadvertent balancing (July 1996 to mid-1997) is being done in the NWPParea, and of the problems that are occurring. The second description will address how inadvertentbalancing is anticipated to be done beginning mid-1997.

JULY, 1996 THROUGH MID 1997

NWPP Control Areas (non-BPA)

• Many NWPP control areas check scheduled and actual interchange hourly, weekly and monthlywith adjacent control areas.

• Each month each control area submits Monthly Central Time reports containing inadvertent datato the NWPP staff.

Bonneville Power Administration

• BPA checks scheduled and actual interchange hourly, weekly and monthly with adjacent controlareas.

• BPA provides the service of providing accurate inadvertent data in their Central Time report.Consequently, BPA chases inadvertent discrepancies to achieve this accuracy. By doing thisservice for the NWPP area, they are by default, the last to provide monthly inadvertent data bysubmitting their Central Time report to the NWPP staff.

NWPP Staff Function

• To close the loop of the individual control areas, the NWPP staff receives and cross checks allCentral Time reports to insure all inadvertent within the NWPP area is balanced. If discrepanciesarise, then the NWPP chases the involved parties to balance.

After-The-Fact Changes

• After-the-fact changes are being made historically and in record numbers in an uncoordinatedfashion leaving some control areas out of balance. BPA, the other control areas, and the NWPPstaff all or in part become involved to resolve the inadvertent imbalances.

MID-1997 FORWARD

Control Area Scheduling Services Organization (CASSO)

• By mid-1997, CASSO will offer a subscription service to provide hourly checks of real time andafter-the-fact interchange balancing. Their data base can immediately point out who hasinadvertent imbalances and will notify the effected parties promptly.

• Each month CASSO, for its subscribers, will submit Central Time report data to the NWPP staff.

NWPP Control Areas

• Those NWPP control areas that do not subscribe to CASSO will give CASSO hourly inadvertentdata. CASSO will use these numbers to check the collective NWPP inadvertent interchangeagainst the NWPP subregion’s external tie flows (RMPP, CA-NV, and AZ-NM).

• Each control area submits Monthly Central Time reports containing scheduled and actualinterchange with adjacent control areas to the NWPP staff.

Bonneville Power Administration

• CASSO will provide the service once performed by BPA to provide inadvertent data to theNWPP staff.

NWPP Staff Function

• To close the loop of the individual control areas, the NWPP staff receives and cross checks allCentral Time reports by non-CASSO subscribers with the inadvertent data provided by CASSOto insure all inadvertent within the NWPP area is balanced. If discrepancies arise, then the NWPPchases the involved parties to balance.

After-The-Fact Changes

• CASSO, affected control areas, and the NWPP staff all or in part will become involved to resolvethe inadvertent imbalances.

PROBLEM CAUSES

• Hundreds of after-the-fact changes are being made each month among control areas hinderingBPA’s ability to balance inadvertent interchange.

• Personnel are not as knowledgeable as they should be (many personnel are new, etc.) to performthe necessary checks and to facilitate the necessary changes within their respective control areaand those of adjacent control areas.

• Backup personnel within many control areas is not adequate and has hindered the reconciliationprocess.

• The separation of transmission from the merchant functions of control areas has caused thetraditional data acquisition paths to be severed. Personnel are in a state of transition and arestruggling to create new processes to gather the data critical to NWPP, WSCC, and NERCreporting purposes.

POSSIBLE SOLUTIONS

You Don’t Bill Until You Balance

Amend NERC Policy to mandate that control areas cannot bill for the previous month until allinadvertent, after-the-fact changes or otherwise, are balanced to all adjacent control areas. Oncebilled, after-the-fact changes cannot be made.

Formalized Procedure

Amend NERC Policy to document the procedure’s that are in place, or develop one at the NERClevel, for inadvertent checking and balancing. Hold control areas accountable to be knowledgeable aspart of an audit/review process and provide adequately trained and backup personnel.


Result of Vote on Policies 1, 3E, and 7

Changes to Policies 1, 3E, and 7 were approved by the Regions on December 3, 1996. Some ofthe Regions offered suggestions for further changes, especially to the Control Performance andDisturbance Control Standards. Several Regions offered specific comments, and these have beenforwarded to the subcommittees for their consideration.

All comments are available on the NERC web site:

ftp://www.nerc.com/pub/sys/all_updl/oc/dl/p137cmts.pdf

Action: None


Policy 3 and 4 and Appendixes 3A and 4B

The Interconnected Operations Subcommittee has made several changes to Policy 3, Sections A,B, and C, Appendix 3A, Policy 4B, and Appendix 4B (attached) as it continues to refine the interchangetransaction and scheduling processes. Subcommittee chair Derek R. Cowbourne will review thesechanges (attached) with the OC.

The Subcommittee proposes many changes to Policies 3A and 3B. A comparison document isincluded. (Please pardon the crudeness of this marked up version. MS Word shows font changes as wellas the important stuff. & DMB)

Appendix 3A includes the latest “tagging” concepts. It will replace Appendix 3B.

The data sharing list was moved from Policy 4B to its new Appendix 4B.

Action: 1. Discuss for approval to send Policy 3A, B, C, and Policy 4B to the Regions for vote.

2. Approve Appendixes 3A and 4B.

Draft: February 24, 1997 P3-1 October 18, 1996

Policy 3 6 Interchange

Policy Subsections EffectiveA. Interchange Transactions July 1, 1997B. Interchange Schedules July 1, 1997C. Schedule Specifications July 1, 1997D. Interconnected Operations Services January 1, 1997E. Transfer Capability January 1, 1997

Introduction to Policy 3

This Policy addresses:

• Responsibilities of all PURCHASING-SELLING ENTITIES involvedin INTERCHANGE TRANSACTIONS.

• Coordination of INTERCHANGE SCHEDULING and

IMPLEMENTATION among CONTROL AREAS to preserveINTERCONNECTION reliability.

• Requirements of CONTROL AREAS to assess and confirmINTERCHANGE TRANSACTIONS.

• Accountability of CONTROL AREAS for implementing all

INTERCHANGE SCHEDULES in a manner that ensures thereliability of the INTERCONNECTIONS.

• Information requirements for INTERCHANGE TRANSACTIONS.

• Requirements of PURCHASING-SELLING ENTITIES that arrange

INTERCHANGE TRANSACTIONS to provide or arrange for thenecessary INTERCONNECTED OPERATIONS SERVICES required tosupport the transactions.

• Requirements of CONTROL AREAS to offer INTERCHANGE

SCHEDULING SERVICES to PURCHASING-SELLING ENTITIES.

NERC Operating Policies place the obligations for operating reliability primarilyon the CONTROL AREA. NERC recognizes that in the open access transmissionenvironment, CONTROL AREAS are assigning some of their responsibilities,especially for transmission security, to other entities. These entities includeIndependent System Operators, and SECURITY COORDINATORS. The who assignresponsibilities to other entities must ensure those entities comply with theNERC Operating Policies.

Revisions for OC approval to send toRegions for vote

Policy 3 && Interchange


A. Interchange Transactions Effective July 1, 1997[Policy 2A—Transmission—Transmission Operations][Policy 5A—Emergency Operations—Coordinating with other Systems][Policy 6A—Operations Planning—Normal Operations][Appendix 3A—Section A. Scenarios of Interchange Schedules and Partiesto Interchange Schedules; Section B. Interchange Transaction RequestTemplate and Examples]

Introduction

Policy 3.A. explains the PURCHASING-SELLING ENTITY’Sresponsibilities for arranging INTERCHANGE TRANSACTIONS andthe CONTROL AREA’S responsibilities for assessing and confirmingINTERCHANGE TRANSACTIONS and implementing INTERCHANGE

SCHEDULES.

PURCHASING SELLING ENTITIES “arrange” INTERCHANGE

TRANSACTIONS & that is, they buy or sell energy and capacity andrecord the transaction by forwarding the required data to theappropriate CONTROL AREA(S). [See Requirement 4 below andAppendix 3.A Section B., “Interchange Transaction RequestTemplate and Examples”]

CONTROL AREAS assess and “approve” or “deny” Interchange TRANSACTIONS based on reliability criteria and adequacy ofINTERCONNECTED OPERATIONS SERVICES and transmission rights.The SENDING CONTROL AREA and RECEIVING CONTROL AREA

confirm the transaction with each other and notify the INTERMEDIARY CONTROL AREAS. These CONTROL AREAS assesswhether INTERCHANGE TRANSACTIONS may be consummatedwhile complying with established reliability criteria and notifyparticipating PURCHASING-SELLING ENTITIES accordingly.

To “implement” the INTERCHANGE TRANSACTION, all affected CONTROL AREAS

incorporate the transaction into their INTERCHANGE SCHEDULES .

Requirements

1. PURCHASING-SELLING ENTITIES responsible for INTERCHANGE

arrangements. Each PURCHASING-SELLING ENTITY shall be responsiblefor all INTERCHANGE arrangements and INTERCHANGE TRANSACTIONS

to which it is a party.

1.1. Transmission services. Each PURCHASING-SELLING ENTITY

shall be responsible for arranging and scheduling transmissionservices necessary for the receipt, transfer, and delivery of theINTERCHANGE.

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Figure 1 – Steps for developinginterchange transactions into interchangeschedules.



1.2. Interconnected Operations Services. Each PURCHASING-SELLING ENTITY must provide or arrange for all associatedINTERCONNECTED OPERATIONS SERVICES necessary to complywith NERC and Regional Council policies.

1.3. Contact personnel. Each PURCHASING-SELLING ENTITY withtitle to an INTERCHANGE TRANSACTION must have, or arrange tohave, personnel directly and immediately available fornotification of INTERCHANGE TRANSACTION changes. Thesepersonnel shall be available from the time that title to theINTERCHANGE TRANSACTION is acquired until theINTERCHANGE TRANSACTION has been completed.

1.4. Identification of control area PARTIES. ANY PURCHASING-SELLING ENTITY(IES) arranging a transaction must identify andinform all CONTROL AREAS that will be parties to thattransaction, including INTERMEDIARY CONTROL AREAS on thescheduling path.

2. Interchange assessment and confirmation. CONTROL AREAS on thescheduling path shall be responsible for assessing and “approving” or“denying” INTERCHANGE TRANSACTIONS on behalf of PURCHASING-SELLING ENTITIES, based on established reliability criteria and adequacyof INTERCONNECTED OPERATIONS SERVICES and transmission rights.

3. INTERCONNECTED OPERATIONS SERVICES. Each CONTROL AREA onthe scheduling path shall be responsible for determining the necessarylevel of INTERCONNECTED OPERATIONS SERVICES for eachINTERCHANGE TRANSACTION.1

4. INTERCHANGE TRANSACTION information. Before an INTERCHANGE

TRANSACTION is implemented, the PURCHASING-SELLING ENTITY shallprovide all of the security-related information listed below for allINTERCHANGE TRANSACTIONS, including the unique identifier number,to all CONTROL AREAS on the scheduling path. The PURCHASING-SELLING ENTITY serving the sink (the transaction receiver) shall beresponsible for providing the unique identifier and submitting theINTERCHANGE TRANSACTION, unless otherwise agreed to by thePURCHASING-SELLING ENTITIES who are party(ies) to the INTERCHANGE

TRANSACTION.

4.1 Application to all transactions. These requirements apply to alltransactions, including those initiated through a broker or power

1 This requirement is not intended to obligate Control Areas outside the United States toprovide transmission services or provide or transmit generation services unless by mutualagreement.



A. Interchange Transactions

exchange.

4.1.1 Transactions initiated through prearranged reservesharing agreements. These requirements do not applyto those transactions established through prearrangedreserve sharing agreements such as “callable reserves.”

The Interconnected Operations Subcommittee is stillreviewing Policies on emergency operations.

4.2 Information template. The information shall be submittedusing the template defined by the NERC InterchangeTransaction Request Template (“Template”) in Appendix 3A.

Automated processes for managing INTERCHANGE TRANSACTION

information are expected in the near future. It is anticipatedthat once the Transaction Identification System is operational,the information will be input electronically by the PURCHASING-SELLING ENTITY and automatically sent to all parties at the sametime.In the interim, for next-hour transactions, it is acceptable toprovide the information without using the Template until theautomated system is available.

4.2.1. Unique INTERCHANGE TRANSACTION identifiernumber. The format for this identifier is: SENDING

CONTROL AREA, PURCHASING-SELLING ENTITY-##A, RECEIVING CONTROL AREA. Unique codes will beestablished to identify each entity. This uniqueidentifier shall be associated with the INTERCHANGE

TRANSACTION from the Sending Control Areas throughall INTERMEDIARY and RECEIVING CONTROL AREAS andPURCHASING-SELLING ENTITIES.

4.2.1.1. CONTROL AREA designations. The CONTROL

AREA designations shall be four-characternames registered on www.tsin.com. EachPURCHASING-SELLING ENTITY shall register aunique four-character name on www.tsin.com.

4.2.1.2. PURCHASING-SELLING ENTITY designations.The PURCHASING-SELLING ENTITY identifiershall consist of the four-character name plus athree-digit + alpha character identifier, which isunique for that date.

4.2.2. Start and end dates for which the INTERCHANGE

TRANSACTION is to be executed. No singleINTERCHANGE TRANSACTION shall span more than one



A. Interchange Transactions

calendar day for the selected time zone unless all detailson the Template are identical for all days. (Seeexamples in Appendix 3A.

The purchasing-selling entity’s Deal Reference Numbermay be used to link transactions that span multiple daysor consist of multiple source-sink pairs.

4.2.2.1. Off-peak Interchange Transactions. For off-peak Interchange Transactions that spanHour Ending 0000, only one template need tosubmitted. (See examples in Appendix 3A).

4.2.3. SENDING, RECEIVING , and INTERMEDIARY CONTROL

AREAS.

4.2.4. Source and sink, including contact, phone, and fax. The identity of the contacts required to initiateINTERCHANGE TRANSACTION curtailment shall beprovided. Each INTERCHANGE TRANSACTION shallcontain only a single source-sink pair until automatedprocesses have been established for managing thetransaction identification information.

Initially, CONTROL AREA designations may serve as thesource and sink identification. The eventual goal is toidentify CONTROL AREA zones or specific generators andloads as the sources and sinks, to the extent possible.

4.2.5. PURCHASING-SELLING ENTITY requesting thetransaction, including contact, phone, and fax.

4.2.6. Chain of ownership of the transaction from thesource to the sink. All PURCHASING-SELLING ENTITIES

in the transaction ownership chain shall be identified.

4.2.7. Amount of energy to be transferred each hour ortime period (with time zone designated).

4.2.8. Energy service type and interruption priority.

4.2.9. Ramp start time and duration.

4.2.10. Amount of and provisions for losses.

4.2.11. Identifiers for applicable transmission reservations(OASIS ASSIGNMENT REFERENCE).



B. Interchange Schedules

This will allow CONTROL AREAS to evaluate adequacy ofreservations, to identify Points of Receipt and Points ofDelivery, and to establish curtailment priorities based on type oftransmission service.

Information regarding adequacy of INTERCONNECTED

OPERATIONS SERVICES shall be available, but is not included inthe Template until scheduling practices are better defined forINTERCONNECTED OPERATIONS SERVICES.

5. INTERCHANGE TRANSACTION modifications. PURCHASING-SELLING

ENTITIES that reallocate (“aggregate” or “split”) an INTERCHANGE

TRANSACTION shall submit new INTERCHANGE TRANSACTION(S) todisplace the modified transactions(s).

5.1. INTERCHANGE TRANSACTIONS in progress. If anINTERCHANGE TRANSACTION is modified while it is in progress,the transaction is terminated and a new transaction is requiredfor the remainder of the transaction period. The energy profileof a transaction may be modified by a CONTROL AREA forcurtailment purposes without replacing the existing transaction.

6. Confidentiality of information. CONTROL AREAS shall not discloseINTERCHANGE TRANSACTION information to any PURCHASING-SELLING

ENTITY not involved in the INTERCHANGE TRANSACTION.

B. Interchange Schedules Effective Beginning July 1, 1997 [Appendix 3A Section B, “Interchange Transaction Request Template andExamples”]

Introduction

Policy 3B prescribes the obligations of CONTROL AREAS when scheduling,confirming, and implementing INTERCHANGE SCHEDULES .

Requirements

1. CONTROL AREAS shall be known to each other. The CONTROL AREAS

that are parties to an INTERCHANGE SCHEDULE shall be known to eachother before confirming and implementing the schedule. The parties toan INTERCHANGE SCHEDULE and the information required by CONTROL

AREAS are illustrated in Appendix 3A.

1.1. Sharing schedule details. The CONTROL AREAS that are partiesto an INTERCHANGE SCHEDULE must enter the details of the



B. Interchange Schedules

schedule into the Interregional Security Network as specified inPolicy 4.B.

2. Interchange Schedule agreement. As a minimum, the SENDING

CONTROL AREA, RECEIVING CONTROL AREA, and INTERMEDIARY

CONTROL AREA(S) shall agree with each other on the magnitude,scheduling path, starting and ending times, ramp start time and duration,terms of interruption for GENERATION SERVICES and TRANSMISSION

SERVICES, and responsibility for operating reserve of the INTERCHANGE

SCHEDULE. This agreement shall be made before either the SENDING orRECEIVING CONTROL AREA makes any generation changes to implementthe interchange schedule.

2.1. Operating Reliability Criteria . CONTROL AREAS shall operatesuch that INTERCHANGE SCHEDULES or schedule changes do notcause any other system to violate established operatingreliability criteria.

2.2. Interchange Schedule confirmation and implementation. The RECEIVING CONTROL AREA is responsible for initiating theCONFIRMATION and IMPLEMENTATION of the INTERCHANGE

SCHEDULE with the SENDING CONTROL AREA. The SENDING

CONTROL AREA and RECEIVING CONTROL AREA shall confirmand implement the INTERCHANGE SCHEDULE with the INTERMEDIARY CONTROL AREAS that are parties to theINTERCHANGE SCHEDULE.

2.2.1 DC tie operator. SENDING and RECEIVING CONTROL

Areas shall coordinate with any dc tie operators on thescheduling path.



C. Schedule Specifications Effective beginning July 1, 1997

Introduction

Policy 3.C. explains the default specificationsfor INTERCHANGE SCHEDULES andINTERCHANGE TRANSACTIONS.

The figure to the right is an example to helpexplain these specifications.

Requirements

1. Period. INTERCHANGE shall begin andend on a CLOCK HOUR unless agreed to otherwise by the SENDING

CONTROL AREA, RECEIVING CONTROL AREA, and INTERMEDIARY

CONTROL AREAS.

1.1. Transaction revisions. Under normal operations, anINTERCHANGE TRANSACTION shall not be revised until the end ofthe current clock hour, unless agreed to otherwise by theSENDING CONTROL AREA, RECEIVING CONTROL AREA, and INTERMEDIARY CONTROL AREAS.

2 Transaction submission time. To provide adequate time for securityassessment, INTERCHANGE TRANSACTIONS shall be submitted to all theCONTROL AREAS on the scheduling path no later than 20 minutes beforethe time at which the transaction is to begin. This Requirement can bewaived if changes to the transactions are required to preserve thesecurity of the Interconnection.

3. Ramp-start times and duration. The SENDING, RECEIVING, and, asapplicable, INTERMEDIARY CONTROL AREAS, shall use the same ramp,start times, and durations.

3.1. Ramp start times. The SENDING, RECEIVING, and, asapplicable, INTERMEDIARY CONTROL AREAS shall begin toramp the INTERCHANGE SCHEDULE at the start and end times ofthe schedule change

3.2. Ramp durations. Ramp durations shall consist of one or moreten-minute periods, with the normal ramp duration equal to oneten-minute period, unless SENDING, RECEIVING, and, asapplicable, INTERMEDIARY CONTROL AREAS agree otherwise.

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Policy 3 6 Interchange

Policy Subsections EffectiveA. Interchange Transactions Beginning January 1, 1997B.Interchange Schedules Beginning JanuaryA. Interchange Transactions July 1, 1997B. Interchange Schedules July 1, 1997C. Schedule Specifications Beginning July 1, 1997D. Interconnected Operations Services Beginning January 1, 1997E. Transfer Capability Beginning January 1, 1997

Introduction to Policy 3

This Policy addresses:

• & Responsibilities of all PURCHASING-SELLING ENTITIES

involved in INTERCHANGE TRANSACTIONS. & Requirements of PURCHASING-SELLING ENTITIES that arrange

an INTERCHANGE TRANSACTION to provide or arrange for thenecessary INTERCONNECTED OPERATIONS SERVICES required tosupport the transaction.

& Requirements of CONTROL AREAS to offer INTERCHANGE

SCHEDULING SERVICES to PURCHASING-SELLING

ENTITIES.Coordination of INTERCHANGE SCHEDULING andIMPLEMENTATION among CONTROL AREAS to preserveINTERCONNECTION reliability.

• & Requirements of CONTROL AREAS to assess and confirmINTERCHANGE TRANSACTIONS.

• Accountability of CONTROL AREAS for implementing all


• Information requirements for INTERCHANGE TRANSACTIONS.

& Accountability of CONTROL AREAS for implementing all


1. & Coordination of INTERCHANGE SCHEDULING andIMPLEMENTATION among CONTROL AREAS to preserveINTERCONNECTION reliability.Requirements of PURCHASING-SELLING ENTITIES that arrange INTERCHANGE TRANSACTIONS

to provide or arrange for the necessary INTERCONNECTED

OPERATIONS SERVICES required to support the transactions.

• Requirements of CONTROL AREAS to offer INTERCHANGE

SCHEDULING SERVICES to PURCHASING-SELLING ENTITIES.

Revisions for OC approval to send toRegions for vote – Comparison doc.

Policy 3 && InterchangeA. Interchange TransactionsNERC Operating Policies place the obligations for operating reliability primarilyon the control area.CONTROL AREA. NERC recognizes that in the open accesstransmission environment, control areasCONTROL AREAS are assigning some oftheirreliability responsibilities, especially for transmission security, to otherentities. These entities include Independent System Operators, and SECURITY

COORDINATORS. Thecontrol areas who assign responsibilities to other entitiesmust ensure those entities comply with the NERC Operating Policies.

A. Interchange Transactions Effective beginning JanuaryJuly 1, 1997[Policy 2A %% Transmission && Transmission2A—Transmission—Transmission Operations][Policy 5A %% Emergency Operations && Coordinating5A—EmergencyOperations—Coordinating with other Systems][Policy 6A %% Operations Planning && Normal6A—Operations Planning—Normal Operations]

Introduction [Appendix 3A—Section A. Scenarios of InterchangeSchedules and Parties to Interchange Schedules; Section B. InterchangeTransaction Request Template and Examples]

Introduction

Policy 3.A. explains the PURCHASING-SELLING ENTITY SENTITY’Sresponsibilities for arranging INTERCHANGE TRANSACTIONS andthe CONTROL AREA SAREA’S responsibilities for assessing andconfirming INTERCHANGE TRANSACTIONS and implementingINTERCHANGE SCHEDULES.

PURCHASING SELLING ENTITIES $arrange#“arrange”INTERCHANGE TRANSACTIONS && that is, they buy or sellenergy,energy and capacity and record the transaction byspecifyingforwarding the requireddata, and forward that data to theappropriate CONTROL AREA(S) according to the interchangetransaction identification system. [See Appendix 3.BSection B]AREA(S). [See Requirement 4 below and Appendix3.A Section B., “Interchange Transaction Request Templateand Examples”]

CONTROL AREAS assess and $confirm#“approve” or “deny”Interchange TRANSACTIONS. TRANSACTIONS based on reliabilitycriteria and adequacy of INTERCONNECTED OPERATIONS SERVICES

and transmission rights. The SENDING CONTROL AREA andRECEIVING CONTROL AREA verifyconfirm the transaction witheach other and notify the CONTRACT INTERMEDIARY CONTROL

AREAS. All aff ectedThese CONTROL AREAS assess whether INTERCHANGE

TRANSACTIONS may be consummated while complying with establishedreliability criteria and notify participating PURCHASING-SELLING ENTITIES

accordingly.

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Figure 1 – Steps for developinginterchange transactions into interchangeschedules.

Policy 3 && InterchangeA. Interchange Transactions

& Contract Intermediary Control Area(s)

& terms of interruption for generation and transmission services

• amount of energy to be transferred,

& start and end times

• ramp rates

• associated Interconnected Operations Services and their providers

3.In terchange assessment and confirmation. CONTROL AREAS shall beresponsible for assessing and confirming INTERCHANGE TRANSACTIONS

on behalf of PURCHASING-SELLING ENTITIES..

4.Interconnected Operations Services. Each CONTROL AREA involved withimplementing the INTERCHANGE TRANSACTION shall be responsible fordetermining the necessary Interconnected Operations Services for itssystem for each INTERCHANGE SCHEDULE.

Guides

1.Interchange Identification. The SENDING CONTROL AREA should assign anidentifier to each INTERCHANGE TRANSACTION that identifies the SENDING

CONTROL AREA. This identifier should accompany the INTERCHANGE

TRANSACTION through all CONTRACT INTERMEDIARY CONTROL AREAS andPURCHASING-SELLING ENTITIES until the TRANSACTION arrives at theRECEIVING CONTROL AREA. The concept of the identification system isexplained in Appendix 3B.

1.1.Changes in ownership. PURCHASING-SELLING ENTITIES that changeownership of an INTERCHANGE TRANSACTION should inform theSENDING CONTROL AREA of the ownership change. The INTERCHANGE

TRANSACTION should retain the identification of the SENDING CONTROL

AREA even as it changes owners.

1.2.Reallocating transactions. PURCHASING-SELLING ENTITIES thatreallocate ($aggregate# or $split#) an INTERCHANGE TRANSACTION

should maintain the identification of the individual transactions thathave been reallocated.

1.2. Interconnected Operations Services. Each PURCHASING-SELLING ENTITY must provide or arrange for all associatedINTERCONNECTED OPERATIONS SERVICES necessary to complywith NERC and Regional Council policies.

1.3. Contact personnel. Each PURCHASING-SELLING ENTITY withtitle to an INTERCHANGE TRANSACTION must have, or arrange tohave, personnel directly and immediately available fornotification of INTERCHANGE TRANSACTION changes. Thesepersonnel shall be available from the time that title to theINTERCHANGE TRANSACTION is acquired until the


INTERCHANGE TRANSACTION has been completed.

1.4. Identification of control area PARTIES. ANY PURCHASING-SELLING ENTITY(IES) arranging a transaction must identify andinform all CONTROL AREAS that will be parties to thattransaction, including INTERMEDIARY CONTROL AREAS on thescheduling path.

2. Interchange assessment and confirmation. CONTROL AREAS on thescheduling path shall be responsible for assessing and “approving” or“denying” INTERCHANGE TRANSACTIONS on behalf of PURCHASING-SELLING ENTITIES, based on established reliability criteria and adequacyof INTERCONNECTED OPERATIONS SERVICES and transmission rights.

3. INTERCONNECTED OPERATIONS SERVICES. Each CONTROL AREA onthe scheduling path shall be responsible for determining the necessarylevel of INTERCONNECTED OPERATIONS SERVICES for eachINTERCHANGE TRANSACTION.1

4. INTERCHANGE TRANSACTION information. Before an INTERCHANGE

TRANSACTION is implemented, the PURCHASING-SELLING ENTITY shallprovide all of the security-related information listed below for allINTERCHANGE TRANSACTIONS, including the unique identifier number,to all CONTROL AREAS on the scheduling path. The PURCHASING-SELLING ENTITY serving the sink (the transaction receiver) shall beresponsible for providing the unique identifier and submitting theINTERCHANGE TRANSACTION, unless otherwise agreed to by thePURCHASING-SELLING ENTITIES who are party(ies) to the INTERCHANGE

TRANSACTION.

4.1 Application to all transactions. These requirements apply to alltransactions, including those initiated through a broker or powerexchange.

4.1.1 Transactions initiated through prearranged reservesharing agreements. These requirements do not applyto those transactions established through prearrangedreserve sharing agreements such as “callable reserves.”

The Interconnected Operations Subcommittee is stillreviewing Policies on emergency operations.

4.2 Information template. The information shall be submittedusing the template defined by the NERC InterchangeTransaction Request Template (“Template”) in Appendix 3A.

Automated processes for managing INTERCHANGE TRANSACTION

1 This requirement is not intended to obligate Control Areas outside the United States toprovide transmission services or provide or transmit generation services unless by mutualagreement.


information are expected in the near future. It is anticipatedthat once the Transaction Identification System is operational,the information will be input electronically by the PURCHASING-SELLING ENTITY and automatically sent to all parties at the sametime.In the interim, for next-hour transactions, it is acceptable toprovide the information without using the Template until theautomated system is available.

4.2.1. Unique INTERCHANGE TRANSACTION identifiernumber. The format for this identifier is: SENDING

CONTROL AREA, PURCHASING-SELLING ENTITY-##A, RECEIVING CONTROL AREA. Unique codes will beestablished to identify each entity. This uniqueidentifier shall be associated with the INTERCHANGE

TRANSACTION from the Sending Control Areas throughall INTERMEDIARY and RECEIVING CONTROL AREAS andPURCHASING-SELLING ENTITIES.

4.2.1.1. CONTROL AREA designations. The CONTROL

AREA designations shall be four-characternames registered on www.tsin.com. EachPURCHASING-SELLING ENTITY shall register aunique four-character name on www.tsin.com.

4.2.1.2. PURCHASING-SELLING ENTITY designations.The PURCHASING-SELLING ENTITY identifiershall consist of the four-character name plus athree-digit + alpha character identifier, which isunique for that date.

4.2.2. Start and end dates for which the INTERCHANGE

TRANSACTION is to be executed. No singleINTERCHANGE TRANSACTION shall span more than onecalendar day for the selected time zone unless all detailson the Template are identical for all days. (Seeexamples in Appendix 3A.

The purchasing-selling entity’s Deal Reference Numbermay be used to link transactions that span multiple daysor consist of multiple source-sink pairs.

4.2.2.1. Off-peak Interchange Transactions. For off-peak Interchange Transactions that spanHour Ending 0000, only one template need tosubmitted. (See examples in Appendix 3A).

4.2.3. SENDING, RECEIVING , and INTERMEDIARY CONTROL

AREAS.

4.2.4. Source and sink, including contact, phone, and fax. The identity of the contacts required to initiateINTERCHANGE TRANSACTION curtailment shall be


provided. Each INTERCHANGE TRANSACTION shallcontain only a single source-sink pair until automatedprocesses have been established for managing thetransaction identification information.

Initially, CONTROL AREA designations may serve as thesource and sink identification. The eventual goal is toidentify CONTROL AREA zones or specific generators andloads as the sources and sinks, to the extent possible.

4.2.5. PURCHASING-SELLING ENTITY requesting thetransaction, including contact, phone, and fax.

4.2.6. Chain of ownership of the transaction from thesource to the sink. All PURCHASING-SELLING ENTITIES

in the transaction ownership chain shall be identified.

4.2.7. Amount of energy to be transferred each hour ortime period (with time zone designated).

4.2.8. Energy service type and interruption priority.

4.2.9. Ramp start time and duration.

4.2.10. Amount of and provisions for losses.

4.2.11. Identifiers for applicable transmission reservations(OASIS ASSIGNMENT REFERENCE).

This will allow CONTROL AREAS to evaluate adequacy ofreservations, to identify Points of Receipt and Points ofDelivery, and to establish curtailment priorities based on type oftransmission service.

Information regarding adequacy of INTERCONNECTED

OPERATIONS SERVICES shall be available, but is not included inthe Template until scheduling practices are better defined forINTERCONNECTED OPERATIONS SERVICES.

5. INTERCHANGE TRANSACTION modifications. PURCHASING-SELLING

ENTITIES that reallocate (“aggregate” or “split”) an INTERCHANGE

TRANSACTION shall submit new INTERCHANGE TRANSACTION(S) todisplace the modified transactions(s).

5.1. INTERCHANGE TRANSACTIONS in progress. If anINTERCHANGE TRANSACTION is modified while it is in progress,the transaction is terminated and a new transaction is requiredfor the remainder of the transaction period. The energy profileof a transaction may be modified by a CONTROL AREA forcurtailment purposes without replacing the existing transaction.

6. Confidentiality of information. CONTROL AREAS shall not discloseINTERCHANGE TRANSACTION information to any PURCHASING-SELLING


ENTITY not involved in the INTERCHANGE TRANSACTION.

B. Interchange Schedules Effective Beginning July 1, 1997 [Appendix 3A Section B, “Interchange Transaction Request Template andExamples”]

Introduction

Policy 3B prescribes the obligations of CONTROL AREAS when scheduling,confirming, and implementing INTERCHANGE SCHEDULES .

Requirements

1.1. CONTROL AREAS shall be known to each other. The CONTROL AREAS

that are parties to an INTERCHANGE SCHEDULE shall be known to eachother before confirming and implementing the schedule. The parties toan INTERCHANGE SCHEDULE and the information required by CONTROL

AREAS isare illustrated in Appendix 3B.3A.

1.1.1.1. Sharing schedule details. The CONTROL AREAS that are partiesto an INTERCHANGE SCHEDULE must enter the details of theschedule into the Interregional Security Network as specified inPolicy 4.B. so that other CONTROL AREAS and SECURITY

COORDINATORS will be able to evaluate the impact of theINTERCHANGE upon the transmission system.

1.2.Identifying purchasing-selling entities. The SENDING CONTROL AREA

and RECEIVING CONTROL AREA, plus SECURITY COORDINATORS, mustknow of any PURCHASING-SELLING ENTITIES that are parties to theINTERCHANGE TRANSACTION so that either TRANSACTION ortransmission curtailment procedures can be coordinated.

1.3.Responsibility to confirm and implement the schedule. TheRECEIVING CONTROL AREA is responsible for initiating theCONFIRMATION and IMPLEMENTATION of the INTERCHANGE SCHEDULE

with the SENDING CONTROL AREA.

2.2. Interchange Schedule agreement. As a minimum, the SENDING

CONTROL AREA, RECEIVING CONTROL AREA, and CONTRACT

INTERMEDIARY CONTROL AREA(S) shall agree with each other on themagnitude, scheduling path, starting and ending times, ramp rates,starttime and duration, terms of interruption for GENERATION SERVICES andTRANSMISSION SERVICES, and responsibility for operating reserve of theINTERCHANGE SCHEDULE. This agreement shall be made before eitherthe SENDING or RECEIVING CONTROL AREA makes any generationchanges to implement the interchange schedule.

2.1.Criteria violations.2.1. Operating Reliability Criteria. CONTROL AREAS shall operate such that INTERCHANGE

SCHEDULES or schedule changes do not cause any other systemto violate established operating reliability criteria.

2.2.2.2. Interchange Schedule confirmation and implementation. TheRECEIVING CONTROL AREA is responsible for initiating the

Policy 3 && InterchangeB. Interchange Schedules

CONFIRMATION and IMPLEMENTATION of the INTERCHANGE SCHEDULE

with the SENDING CONTROL Interchange confirmation andimplementation with intermediary control areas.AREA. TheSENDING CONTROL AREA and RECEIVING CONTROL AREA shallconfirm and implement the INTERCHANGE SCHEDULE with theCONTRACT INTERMEDIARY CONTROL AREAS that are parties to theINTERCHANGE Schedule.

SCHEDULE.

2.2.1 DC tie operator. SENDING and RECEIVING CONTROL

Areas shall coordinate with any dc tie operators on thescheduling path.

Policy 3 – Interchange

C. Schedule Specifications Effective beginning July 1, 1997

Introduction

Policy 3.C. explains the default specificationsfor interchange schedules.INTERCHANGE

SCHEDULES and INTERCHANGE TRANSACTIONS.

The figure to the right will is an example to helpexplain these specifications.

Requirements

1.1. Period. INTERCHANGE shall begin andend on a CLOCK HOUR unless agreed to otherwise by the SENDING CONTROL AREA, RECEIVING

CONTROL AREA, and CONTRACT INTERMEDIARY CONTROL AREAS. INTERMEDIARY CONTROL AREAS.

1.1.1.1. Transaction revisions. Under normal operations, an INTERCHANGE TRANSACTION shallnot be revised until the end of the current clock hour, unless agreed to otherwise by theSENDING CONTROL AREA, RECEIVING CONTROL AREA, and INTERMEDIARY CONTROL

AREAS.CONTRACTINTERMEDIARY CONTROL AREAS.

2 Transaction submission time. To provide adequate time for security assessment,INTERCHANGE TRANSACTIONS shall be submitted to all the CONTROL AREAS on the schedulingpath no later than 20 minutes before the time at which the transaction is to begin. ThisRequirement can be waived if changes to the transactions are required to preserve the security ofthe Interconnection.

3.Ramp rates. The SENDING CONTROL AREA and RECEIVING CONTROL AREA3. Ramp-start times andduration. The SENDING, RECEIVING, and, as applicable, INTERMEDIARY CONTROL AREAS, shalluse the same ramp rate (MW/min), start times, and durations.

3.1.3.1. Ramp start times. The SENDING, RECEIVING, and, as applicable, INTERMEDIARY

CONTROL AREAS Ramp start times. The SENDING CONTROL AREA and RECEIVING

CONTROL AREA shall begin to ramp the INTERCHANGE TRANSACTION SCHEDULE at thestart and end times of the transaction.schedule change

3.2.3.2. Ramp durations. Ramp durations shall consist of one or more 10-minuteten-minute periods, with the normal ramp duration equal to one ten-minute period, unless theSENDING CONTROL AREA and RECEIVING CONTROL AREA agree otherwise.

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Draft: February 24, 1997 A3B −1

Appendix 3A & Interchange Schedules

Appendix SubsectionsA. Scenarios of Interchange Schedules and Parties to Interchange SchedulesB. Interchange Transaction Request Template and Examples

A. Scenarios of Interchange Schedules and Parties toInterchange Schedules

For the interconnected CONTROL AREAS A, B andC in the figure to the right, the followingtransactions, numbered 1 through 8, are eachconsidered to be one INTERCHANGE SCHEDULE asreferred to in Policy 3A, Requirement 1.1. Allparties to that INTERCHANGE SCHEDULE shall beknown to each of the participating CONTROL

AREAS in advance of the SCHEDULE beingimplemented. Items 9 and 10 describe interchangescenarios involving PURCHASING-SELLING

ENTITIES with load or generation (P) and powermarketers (M). Items 11/12 and 13/14 covermultiple transactions.

1. A sells to B. Parties are A and B.

2. B sells to C. Parties are B and C.

3. C sells to B. Parties are B and C.

4. B sells to A. Parties are A and B.

5. A sells to C using Transmission Service through B. Parties are A, B, and C.

6. C sells to A using Transmission Service through B. Parties are A, B, and C.

7. Upon request from A or C, B buys from A and sells to C, billing C the price of power from Aplus an approved transmission service charge, and the power from A is continuously identified asthe power to C. Parties are A, B, and C.

8. Upon request from A or C, B buys from C and sells to A, billing A the price of power from Cplus an approved transmission service charge, and the power from C is continuously identified asthe power to A. Parties are A, B, and C.

9. PURCHASING-SELLING ENTITY P in HOST CONTROL AREA A buys from B. Parties are A and B. Purchasing-selling entity P has arranged for Interconnected Operations Services with its HOST

CONTROL AREA A, and possibly B and C.

10. PURCHASING-SELLING ENTITY in HOST CONTROL AREA A buys from Marketer M. Marketer Mbuys from C. Parties are A, B and C. Purchasing-selling entity P has arranged for

A

B

CP

Purchasing-Selling Entity(Transmission Customer)

Host Control Area(Transmission Provider)

MMarketer

For OC approval.

Appendix 3A Interchange Schedules

Draft: February 24, 1997 A3A −2

Interconnected Operations Services with its HOST CONTROL AREA A, and possibly B and C. Marketer M has revealed to A, B, and C that C is the SENDING CONTROL AREA, A is theRECEIVING CONTROL AREA, and B is providing transmission services.

11/12. B schedules its share of generation located in CONTROL AREA A and sells to CONTROL AREA C. Therefore, A and B are parties of one INTERCHANGE SCHEDULE, and B and C are parties to asecond INTERCHANGE SCHEDULE.

13/14. B buys from A and possibly also from other CONTROL AREAS, utilizing the purchased power assystem resources to meet its load and reserve requirements. Opportunities arise to sell power toC and possibly other CONTROL AREAS from these system resources.

These opportunity sales from the system resources would not be considered to be part of thesame INTERCHANGE SCHEDULES as the purchased power because the sales could come from anycombination of purchases and internal generation. In this case, the power from A (and others)could not be continuously identified with the power to C (and others). Therefore, A and B areparties to one interchange schedule, and B and C are parties to a second interchange schedule.

In this case where power purchases cannot be continuously identified with specific sales, theinvolved control areas must be receptive to information requests from control areas with loadingproblems, and make best efforts to provide flow path information to help resolve the problem.



B. Interchange Transaction Request Template

Notes:

1. The next page is the blank template with definition numbers.2. The definitions follow the template.3. The three examples follow the definitions (these are being revised to be in

conformance with the revised template).

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NERC INTERCHANGE TRANSACTION REQUEST

Transaction 3 INTERCHANGE TRANSACTION ID NUMBERStart Date: 2 1 SCA , UNIQUE MKT ##### , RCA

Stop Date: 66 Superceding Transaction ID # (if any)Energy Profile Ramp Info

Purchasing/Selling Entity (PSE) 4 Start Stop MW MWH Ramp Ramp PSE Deal Reference # 5 Start Duration

PSE Contact Name 6 20 21 22 23 24 25PSE Phone Number 7 02

PSE 24 hr Phone Number 8 03PSE Fax or Email 9 04

Source Generator Name 10 05Source Phone 11 06

Sending Control Area | Phone # 12 13 07ending Control Area Fax or Email 14 08

Load Or Sink Entity 15 09Receiving Control Area | Phone # 16 17 10eceiving Control Area Fax / Email 18 11

Remarks or Key info: 19 12

19 13

19 1415

----------- Transaction Path ------------ OASIS 16CA TP PSE Product Resv. # 17

1819

30 31 32 33 34 2021222324

CA or Loss Accounting MW @ MW @

TP START STOP LOSSES POR POD

50 51 52 53 54 5523456789

101112131415

ADMINISTRATIVE DATE TIME INITIALS 16Request Received 60 17Approved / Deny 61 18Curtailed: 62 19Cancelled: 63 20Superceded by: 64 21Reason For Denial: 65 22

23 Template Version Date 2/19 Page ____/_____ 24

PDT MDT CDT EDT ADT

PST MST CST EST AST



1Interchange Transaction ID NumberThe number assigned by the Purchasing-Selling Entity (PSE) serving the Sink unless otherwise agreed to by thePSEs that are party to the Interchange Transaction. (Refer to Policy 3.A.4.) It will be in the format of SourceControl Area, PSE Unique Number, Sink Control Area. (SCA,PSE###A,RCA). Standard four-character names willbe used to designate Control Areas.

2Transaction Dates The dates the transaction will start and the date the Transaction will end.

3Time Zone

The Time Zone that will be used for the actual initiation and termination of the transaction (Circle one). Acircle is provided to select the correct time zone.

4Purchasing/Selling Entity

The name of the deal maker or any entity that is requesting the energy transaction. Use the standardTSIN.COM transmission four-character designation.

5PSE Deal Reference #

The deal number the PSE uses to identify the transaction if different from the Interchange Transaction IDNumber.

6PSE Contact Name

Individual at the PSE responsible for notifying all parties in the schedule chain of any schedule changes.

7, 8, 9PSE Telephone Number and PSE Fax Number or E-Mail

PSE information that will be used for billing and other information for Control Area operators to use forimplementation details of the transaction.

10, 11Source Generation Name and Phone Number

Identity of the exact source of generation or generation pool and a 24-hour phone number to contact thegeneration operator.

12, 13, 14Sending Control Area Information

The Sending Control Area operator information (ID, Phone Number, and Fax Number or E-Mail) wherethe source of generation resides.

15Load or Sink Entity

Identity of the actual consumer of the electricity (e.g., load or sink).


16, 17, 18Receiving Control Area Information

The Receiving Control Area operator information (ID Number, Phone Number, and Fax Number or E-Mail)of the sink.

19Remarks

Terms for interruption of the transaction and other important remarks.

Energy Profile

20Start Time

Start time (in 24-hour time format) of the transaction, defined as the specific time of the beginning ofservice.

21Stop Time

Stop time (in 24-hour time format) of the transaction, defined as the specific time of the termination ofservice.

22MW

The maximum amount of megawatts transported for the hour.

23MWh

The accumulated amount of megawatts transferred for the period defined by the start and stop times andramp start and duration.

24Ramp Start

The time (in 24-hour time format) when the ramp(s) used to start, change, or terminate the schedule begin.

25Ramp Duration

The ramp duration in minutes. The default if not defined is ten minutes.

Transaction Path

30Control Area

The NERC defined Control Area. Use the standard TSIN.COM Control Area four-character designation.

31Transmission Provider

The provider of the transmission facilities for this portion of the path. Use the standard TSIN.COMTransmission Provider four character designation.



32Purchasing/Selling Entity

The responsible owner of the transaction at each point of the path. Use the standard TSIN.COM PSE four-character designation.

33Product

The product or service that the entity is providing from the following standard list: (Transmission:Recallable Hourly [RH]/Daily [RD]/Weekly [RW]/Monthly [RM]/Yearly [RY]; Non-Recallable Hourly[NRH]/Daily [NRD]/Weekly [NRW]/Monthly [NRM]/Yearly [NRY]); (Energy: Non-Firm; Firm).

The standard name may be augmented with additional specific nomenclature. In addition, the followingdesignations are used for certain roles: Generator (G), Load (L).

34OASIS Assignment Reference

OASIS Assignment Reference (provided by the OASIS) associated with the transmission provider.

Loss Accounting

50CA or TP The Control Area or Transmission Provider that requires accounting for megawatt losses for theInterchange Transaction.

51Start The time in 24-hour format defining the specific time the loss accounting will start. The start time shall notbe outside of the times listed in the Energy Profile section.

52Stop

The time in 24-hour format defining the specific time the loss accounting will end. The end time shall notbe outside of the times listed in the Energy Profile section.

53Losses

The megawatt amount that is accounted for as losses across a Transmission Provider or a Control Area.

54MW at POR

The amount of megawatts received by the Control Area/Transmission Provider at the Point of Receipt(POR) in the time period defined by the Start/Stop times.


55MW at POD

The amount of megawatts delivered by the Control Area/Transmission Provider at the Point of Delivery(POD) in the time period defined by the Start/Stop times.

Administrative (For use by the Control Area)

60Request Received

The date and time the request was received. Also the initials of the person receiving the request.

61Approved/Denied

“Approved” or “Denied” should be circled to reflect the decision of the Control Area receiving the request,with the time that the decision was made, and the initials of the person posting the acceptance or denial. A circle isprovided to select “approved” or “denied.”

62Transaction Curtailed

If curtailment occurs, enter date, time, and the standard identifier of the entity requiring curtailment.

63Transaction Termination

If termination occurs, enter date, time, and the standard identifier of the entity requiring termination.

64Superseded by:

If the Transaction or a portion thereof is superseded by a new Transaction, enter the InterchangeTransaction ID Number(s) of the new Transaction(s).

65Reason for Denial, Curtailment, or Cancellation

A hand written explanation of the reason given for denial, curtailment, or termination of the Transaction.

66Superseding Transaction ID # (if any)

If the Transaction is the successor of a superseded transaction, enter the Interchange Transaction IDNumber of the superseded Transaction.



EXAMPLE 1 NERC INTERCHANGE TRANSACTION REQUEST

Transaction INTERCHANGE TRANSACTION ID NUMBERStart Date: 1/11/97 BREC, ECI2446, TUEG

Stop Date: 1/11/97 Superceding Transaction ID # (if any)

Energy Pro file Ramp InfoPurchasing/Selling En tity (PSE) Electric Clearinghouse, Inc. Start Stop MW MWH Ramp Ramp

PSE Deal Reference # ECI 2446 Start Duration

PSE Contact Name 01 200 200 23:55 10PSE Phone Number 713-507-6576 02 200 200

PSE 24 hr Phone Number 03 200 200PSE Fax or Email 713-507-6504 04 200 200

Source Generator Name BREC 05 200 200Source Phone 555-111-5555 06 200 200

Sending Control Area | Phone # BREC 07 200 200Sending Control Area Fax or Email 08 200 200

Load Or Sink Entity TUEG 09 200 200Receiving Control Area | Phone # TUET 10 200 200Receiving Control Area Fax / Email 214-743-6884 11 200 200

Remarks or Key info: 12 200 200 13 200 200

14 200 200----------- Transaction Path ------------ OASIS 15 200 200

CA TP PSE Product Resv. # 16 200 20017 200 200

BREC G, NF 18 200 200 19 200 200

TVA TVA ECI NF 1448 20 200 200 21 200 200

EES EES ECI NF 198 22 200 200 23 200 200

CSW CSW ECI NF N/A 24 200 200 23:55 10 4800

TU TUET TUEG NF N/A CA or Loss Accounting MW @ MW @ TP Start Stop Losses POR POD

010203040506070809101112131415

ADMINISTRATIVE DATE TIME INITIALS 16Request Received 1/10/97 9:20 $(/ 17Approved / Deny 1/10/97 11:00 .(6 18Curtailed: 19Cancelled: 20Superceded by: 21Reason For Denial: 22

23 Template Version Date 2/19 Page _1___/__1___ 24

PST MST CST EST AST

J. Hadden

555-111-2222555-123-4567

214-812-6245214-743-6900

PDT MDT CDT EDT ADT



Example 1 Description

Description for the Example 1 transaction between Big Rivers Electric Coop. and TUElectricarranged by Electric Clearinghouse, Inc

BREC, G, NF

Big Rivers Electric Coop. is the generator of the energy (source) and the Control Area where theGenerator is located. Big Rivers Merchant group (purchasing/selling entity) is selling energy asa “non-firm” product.

TVA, TVA, ECI, NF, 1448

Electric Clearinghouse, Inc. (ECI) has purchased the energy from BREC and has secured fromthe OASIS NODE a transmission reservation (#1448) for access across TVA’s transmissionsystem which is located within TVA’s control area for transportation of the NF energy.

EES, EES, ECI, NF, 198

ECI has secured from the OASIS NODE a transmission reservation (#198) for access acrossEES’s transmission system, which is located within EES’s control area for transportation of theNF energy.

CSW, CSW, ECI, NF, N/A

ECI contacted CS&W for transmission access of the NF energy across the HVDC tie intoERCOT. An OASIS reservation is not necessary to schedule energy across the tie. This processis accomplished directly with CS&W as operator of the tie.

TU, TUET, TUEG, NF, N/A

ECI will have the NF energy moved over TU Electric’s transmission system (TUET) to TUElectric’s merchant function (TUEG) which is the load or ultimate point of delivery. An OASISreservation is not required within ERCOT as all transmission capacity is purchased on an annualbasis by the load entities.

Losses were handled in four different manners on this one transaction and therefore were tocomplicated to address on one form.



NERC INTERCHANGE TRANSACTION REQUEST

Transaction INTERCHANGE TRANSACTION ID NUMBERStart Date: 7/1/97 PST MST CST EST AST CE , AEPM102A , AEP

Stop Date: 7/1/97 PDT MDT CDT EDT ADT Superceding Transaction ID # (if any)

Energy Profile Ramp InfoPurchasing/Selling Entity (PSE) AEP MARKETING Start Stop MW MWH Ramp Ramp

PSE Deal Reference # AEPM102A Start Duration

PSE Contact Name DAN KRUEGER 0615 0645 100 50 0615 10PSE Phone Number 614 222-8787 0645 0715 300 150

PSE 24 hr Phone Number 614 222-8787 0715 0745 500 250PSE Fax or Email aep.marketer.com 0745 1845 700 7700

Source Generator Name CE 1845 1915 500 250Source Phone 630 232-7631 1915 1945 300 150

Sending Control Area | Phone # CE 630-232-7631 1945 2015 100 50 2015 10Sending Control Area Fax or Email ce.control.com 08

Load Or Sink Entity AEP 09Receiving Control Area | Phone # AEP 614-555-0898 10Receiving Control Area Fax / Email aep.control.com 11

Remarks or Key info: 12**AEP PURCHASE FOR NATIVE LOAD - NO OASIS RESV. 13REQUIRED 14

----------- Transaction Path ------------ OASIS 15CA TP PSE Product Resv. # 16

CE/G CEM NF-DAILY 17CE RD 7273 18

POR\CE-POD\AEP 19AEP RD ** 20

POR\CE-POD\AEP 21AEP/L AEPM NF-DAILY 22

2324

CA or Loss Accounting MW @ MW @

TP Start Stop Losses POR POD010203040506070809101112131415

ADMINISTRATIVE DATE TIME INITIALS 16Request Received 6/30/97 1400 jdl 17Approved / Deny 6/30/97 1415 jdl 18Curtailed: 19Cancelled: 20Superceded by: 21Reason For Denial: 22

23 Template Version Date 2/19 Page 1/1 24

Example 2



Example 2 Description

Example 2 is intended to represent a simple adjacent control area interchange transaction, involving only theaffiliated PSE(s) for Commonwealth Edison (CE) and American Electric Power (AEP). The AEP marketing group(AEPM) has filled out the template and sent it to the transmission provider groups, the control area operationsgroup1 for each company, and the source PSE (CE).

The interchange transaction will start and stop on 7/1/97 and the agreed time zone will be Central Standard Time.

The Transaction ID number is formatted as the Sending CA, unique PSE ID, Receiving CA,CE, AEPM102A, AEP. The number was assigned by AEPM.

The AEPM has completed the section listing PSE, Source, Sink, Control area contacts, phone numbers and in thiscase “e-mail” addresses.

In the area titled “Remarks or Key info” he/she notes that because this interchange transaction is for native load - noOASIS reservation is required, indicating that no OASIS reference number will be listed with the AEP portion of thetransmission service.

Transaction Path

CE/G - Commonwealth Edison is the source control area and the generator of the product.CEM - The affiliated PSE for Commonwealth Edison.NF -DAILY - The product sold as non-firm daily energy

CE - Transmission provider2RD - The product sold as recallable daily.POR\CE- POD\AEP - The point of receipt (POR) from the CE transmission provider perspective is theCE system, the point delivery (POD) is the AEP system.

AEP - Transmission providerRD - The product sold as recallable daily.POR\CE- POD\AEP - The point of receipt (POR) from the AEP transmission provider perspective is theCE system, the point delivery (POD) is the AEP system.

AEP/L - American Electric Power is the sink control area and the has the “load” for the energy product sold.

Request Received - Date and time the template was received, and initials of the person that received the request.

Approved - The date and time that the information contained on the template has been verified and approved.

Energy Profile - Start is the specific time that the interchange schedule will begin (0615)Stop is the specific time that the interchange schedule will end (0645)3MW- the amount of megawatts scheduled in the time period defined by the “Start” and

“Stop” times.MWH - The accumulated megawatts for the time period defined by the “Start” and

“Stop” times.4Ramp Start - Listed at 0615 which indicated the ramp will start with the start of the

1 This example assumes that generation dispatch is done by someone in the control area operations group.2 If the transmission provider resides in a “host control area” the control area should be listed in the CA column.3 Several energy schedules are utilized to represent varying megawatt levels throughout the interchange transaction.4 If ramping on or off a schedule occurs before or after an interchange schedule defined by the start and stop timesMWH accumulation may occur outside of those defined times.



interchange schedule (if AEP and CE agreed to start the ramp 5 minutes before the start of the interchange schedule it would have been listed as 0610)

Ramp Duration - AEP and CE have agreed to ramp onto the schedule over a 10 period.

Loss Accounting - Requires no entries in this example.

Draft: February 24, 1997

Policy 4 6 SystemCoordination

B. Operational Security Information Effective Jan. 1, 1998

Requirements

1. Use of Electric System Security Data. The Electric System SecurityData referred to in this Policy and shared over the Interregional SecurityNetwork shall be used only for operational security analysis and shallnot be made available to nor used by Purchasing-Selling Entities in theretail or wholesale merchant function.

2. Data confidentiality. All recipients of data from the InterregionalSecurity Network (ISN) shall sign the NERC Confidentiality Agreementfor Electric System Security Data. [Appendix 4B, Section B, “DataConfidentiality Agreement”]

3. Data required from Control Areas. Each CONTROL AREA shallprovide its SECURITY COORDINATOR(S) with the Electric SystemSecurity Data that is necessary to allow THE SECURITY COORDINATOR(S)to perform its operational security assessments and coordinate reliableoperations.

3.1. Data list. CONTROL AREAS shall provide the data as listed inAppendix 4B, “Electric System Security Data, Section A,Electric System Security Data List”, unless otherwise agreed toby the CONTROL AREAS and their SECURITY COORDINATOR(S).

4. Data exchange among SECURITY COORDINATORS. Upon request,SECURITY COORDINATORS shall, via the ISN, exchange with each otherElectric Security Data that is necessary to allow the SECURITY

COORDINATORS to perform their operational security assessments andcoordinate their reliable operations.

4.1. Data list. SECURITY COORDINATORS shall share with each otherthe data as listed in Appendix 4B, “Electric System SecurityData, Section A, Electric System Security Data List”, unlessotherwise agreed to.

5. Data exchange among Control Areas. Upon request, Each CONTROL

AREA and other entities shall provide to CONTROL AREAS and otherentities with immediate responsibility for operational security, theElectric Security Data that is necessary to allow the CONTROL AREA orother such entity to perform its operational security assessment and tocoordinate reliable operations.

5.1. Data list. CONTROL AREAS and other entities shall provide thedata as listed in Appendix 4B, “Electric System Security Data,Section A, Electric System Security Data List”, unless otherwise

Revisions for OC approval to send to Regions for vote.

Introstatementmade intoRequirement.


agreed to by the CONTROL AREAS and other entities withimmediate responsibility for operational security.

6. Information from purchasing-selling entities. PURCHASING-SELLING ENTITIES shall provide information as requested by their hostcontrol areas to enable these control areas to conduct operationalsecurity assessments and coordinate reliable operations.

Policy 4 6 SystemCoordination

B. Operational Security Information EffectiveBeginning Jan. 1, 1998

[Appendix 7A, Section D && Regional and Interregional Telecommunications && InterregionalSecurity Network]

Introduction

Operational security requires information about the $health# of the Interconnection and what the otherCONTROL AREAS are doing. This information provides the CONTROL AREA with a better understandingof the forces that affect its operations. This information also provides the input to the CONTROL AREAS

and SECURITY COORDINATOR security analysis programs.

1.Through the Interregional Security Networks ISN, this information is available to other control areas,Security Coordinators, and any other entities who have immediate responsibility for operational securitywithin the INTERCONNECTION, to enable operational security assessments. This information must beused only for operational security analysis and shall not be made available to nor used byPURCHASING-SELLING ENTITIES in the retail or wholesale merchant function.

Requirements

1. Information updated at least every ten minutes. At the request of an entity with immediateresponsibility for operational security,following minimum information to the ISN, updated atleast every ten minutes: This information mustUse of Electric System Security Data. TheElectric System Security Data referred to in this Policy and shared over the Interregional SecurityNetwork shall be used only for operational security analysis and shall not be made available tonor used by Purchasing-Selling Entities in the retail or wholesale merchant function function.

1.1.Transmission data. Transmission data for all Interconnections plus all other facilitiesconsidered key, from a reliability standpoint:

1.1.1.Status1.1.2.MW or ampere loadings1.1.3.MVA capability1.1.4.MVAr loadings and voltages1.1.5.Transformer tap and phase angle settings

1.2.Generator data. Generator data for all generating units that are considered key, from areliability standpoint:

1.2.1.Status1.2.2.MW and MVAr capability1.2.3.MW and MVAr net output1.2.4.Status of automatic voltage control facilities

Revisions for OC approval to send to Regions for vote. Comparison doc.

Data list moved to newAppendix 4B.

Policy 4 && System Coordination


B. System Coordination1.3.Operating Reserve

1.3.1.MW reserve available within ten minutes

1.4.Control area demand

1.4.1.Instantaneous

1.5.Interchange

1.5.1.Instantaneous actual interchange with each CONTROL

AREA.

1.5.2.Current INTERCHANGE SCHEDULES with each CONTROL

AREA by individual transaction, including interchangeidentifiers, and reserve responsibilities.

1.5.3.Interchange schedules for next 24 hours

1.6.Area Control Error and Frequency

1.6.1.Instantaneous area control error1.6.2.Clock hour area control error1.6.3.System frequency at one or more locations in the control

area

2.Other operating information updated as soon as available. At the requestof an entity with responsibility for operational security, the followinginformation shall be posted and updated as soon as available.

2.1.Forecast of operating reserve at peak, and time of peak for currentday and next day.

2.2.Forecast peak demand for current day and next day.2.3.Forecast changes in equipment status2.4.New facilities in place2.5.New or degraded special protection systems2.6.Emergency operating procedures in effect2.7.Severe weather, fire, or earthquake2.8.Multi-site sabotage

3.2. Data retention. There are no requirements on any control area orRegion to retain the data that they make available onconfidentiality. Allrecipients of data from the Interregional Security Network. Therefore, ifthe recipient of the data wishes to access historical data, it shall establisha method for saving the data it obtains from the Network.Network (ISN)shall sign the NERC Confidentiality Agreement for Electric SystemSecurity Data. [Appendix 4B, Section B, “Data ConfidentialityAgreement”]

3. Data required from Control Areas. Each CONTROL AREA shallprovide its SECURITY COORDINATOR(S) with the Electric System

Policy 4 && System Coordination


B. System CoordinationSecurity Data that is necessary to allow THE SECURITY COORDINATOR(S)to perform its operational security assessments and coordinate reliableoperations.

3.1. Data list. CONTROL AREAS shall provide the data as listed inAppendix 4B, “Electric System Security Data, Section A,Electric System Security Data List”, unless otherwise agreed toby the CONTROL AREAS and their SECURITY COORDINATOR(S).

4. Data exchange among SECURITY COORDINATORS. Upon request,SECURITY COORDINATORS shall, via the ISN, exchange with each otherElectric Security Data that is necessary to allow the SECURITY

COORDINATORS to perform their operational security assessments andcoordinate their reliable operations.

4.1. Data list. SECURITY COORDINATORS shall share with each otherthe data as listed in Appendix 4B, “Electric System SecurityData, Section A, Electric System Security Data List”, unlessotherwise agreed to.

5. Data exchange among Control Areas. Upon request, Each CONTROL

AREA and other entities shall provide to CONTROL AREAS and otherentities with immediate responsibility for operational security, theElectric Security Data that is necessary to allow the CONTROL AREA orother such entity to perform its operational security assessment and tocoordinate reliable operations.

5.1. Data list. CONTROL AREAS and other entities shall provide thedata as listed in Appendix 4B, “Electric System Security Data,Section A, Electric System Security Data List”, unless otherwiseagreed to by the CONTROL AREAS and other entities withimmediate responsibility for operational security.

6. Information from purchasing-selling entities. PURCHASING-SELLING ENTITIES shall provide information as requested by their hostcontrol areas to enable these control areas to conduct operationalsecurity assessments and coordinate reliable operations.

Draft: February 24, 1997 A4B-1

Appendix 4B -- Electric SystemSecurity DataAppendix SubsectionsA. Electric System Security Data ListB. Confidentiality Agreement for Electric System Security Agreement

A. Electric System Security Data List

1. Information updated at least every ten minutes. The followinginformation shall be updated at least every ten minutes:

1.1. Transmission data. Transmission data for all Interconnections plusall other facilities considered key, from a reliability standpoint:

1.1.1. Status

1.1.2. MW or ampere loadings

1.1.3. MVA capability

1.1.4. Transformer tap and phase angle settings

1.1.5. Key voltages

1.2. Generator data.

1.2.1. Status

1.2.2. MW and MVAR capability

1.2.3. MW and MVAR net output

1.2.4. Status of automatic voltage control facilities

1.3. Operating reserve

1.3.1. MW reserve available within ten minutes

1.4. Control Area Demand

1.4.1. Instantaneous

1.5. Interchange

1.5.1. Instantaneous actual interchange with each control area.

1.5.2. Current INTERCHANGE SCHEDULES with each control areaby individual transaction INTERCHANGE TRANSACTION,including interchange identifiers, and reserveresponsibilities.

1.5.3. Interchange schedules for the next 24 hours

1.6. Area Control Error and Frequency

1.6.1. Instantaneous area control error

1.6.2. Clock hour area control error

1.6.3. System frequency at one or more locations in the controlarea

For OC approval.

Draft: February 24, 1997 A4B-2

2. Other operating information updated as soon as available

2.1. Forecast of operating reserve at peak, and time of peak for currentday and next day.

2.2. Forecast peak demand for current day and next day.

2.3. Forecast changes in equipment status

2.4. New facilities in place

2.5. New or degraded special protection systems

2.6. Emergency operating procedures in effect

2.7. Severe weather, fire, or earthquake

2.8. Multi-site sabotage

3. Data retention. There are no requirements on any control area or Region toretain the data that they make available on the Interregional SecurityNetwork. Therefore, if the recipient of the data wishes to access historicaldata, it shall establish a method for saving the data it obtains from theNetwork.

B. Confidentiality Agreement for Electric System Security Data

Draft: February 10, 1997 - 4 -

3.4. Security Data. Information to be used for analyzing the operational security of the

Interconnection. Security Data is available from Security Coordinators or from the

Interregional Security Network.

3.5. Data Supplier. Any entity who supplies Security Data, either manually or automatically,

to their Security Coordinator(s) other Security Coordinators, or other Control Areas.

Examples include Control areas, Security Coordinators, and other entities who are

directly responsible for the immediate, real-time operations of the bulk electric system.

3.6. Data Recipient. Control areas, Security Coordinators and other entities who are directly

responsible for the immediate, real-time operations of the bulk electric system, who

obtain Security Data, either manually or automatically, from their Security

Coordinator(s) or from the Interregional Security Network.

3.7. Interregional Security Network. The telecommunications and data system used to

share operating information, including Security Data, among the Data Recipients.

3.8. Energy Merchant Function. Any purchase or sale of electric energy for any

commercial reason. Emergency transactions arranged through predetermined

agreements, such as callable reserves within a Reserve Sharing Group, are not included.

3.9. Merchant Employee. Within an organization, any employee who engages in Energy

Merchant Functions.

4. Standards of Conduct. A Data Recipient must conduct its business to conform with the

following standards:

4.1. General Rules.

4.1.1. Except as emergency conditions dictate as discerned by a Security Coordinator

or Control Area system operators, the employees of a Data Recipient must

function independently of the Merchant Employees within that organization or

its affiliates.

4.1.2. Notwithstanding any other provisions herein, in emergency circumstances that

could jeopardize operational security, Data Recipients may take whatever steps

are necessary to maintain system security. Data Recipients must report to the

Security Coordinator each emergency that resulted in any deviation from this

agreement within 12 hours of such deviation.



4.2. Employee Conduct.

4.2.1. Prohibitions. Any Merchant Employee of the Data Recipient or its affiliate,

engaged in Energy Merchant Functions, is prohibited from:

4.2.1.1. Having access to the Security Data, and

4.2.1.2. Having access to the system control center or similar facilities used for

transmission operations or reliability functions in which Security Data is

displayed if that access differs in any way from the access available to

any other entity.

4.2.2. Employee Transfers. Employees engaged in either the Energy Merchant

Function (Merchant Employees) or real-time transmission system operations

reliability function are not precluded from transferring between functions as long

as the transfer is not used as a means to circumvent the standards of this

agreement. Notice of any employee transfer between reliability and Energy

Merchant Functions shall be provided on the Open Access Same-Time

Information System and to the Security Coordinator within 24 hours of the

transfer.

4.2.3. Disclosure. Any employee of the Data Recipient, or any employee of an

affiliate, engaged in system operation reliability functions shall not disclose to

Merchant Employees of the Data Recipient, or any of its affiliates, any Security

Data concerning the operating conditions of the electric system based on data

received as related to this agreement, to the extent laws allow.

4.2.3.1. Exceptions include Security Data from the Data Supplier’s own

system that the Data Supplier places on the OASIS or makes

available to the general public.

4.2.3.2. The Data Recipient shall not, even under conditions of

confidence, make available, disclose, provide, or communicate

the Security Data to any other party who is not a signatory to this

Agreement to the extent laws allow.

4.2.4. Compliance. The Data Recipient must educate its employees, and any

employee of an affiliate engaged in transmission system operations, in the



provisions of this Agreement and provide any information upon request to the

Regional Security Coordinator necessary to determine compliance with the terms

and conditions of this agreement, including confidentiality agreements that

include the provisions of this agreement.

5. Disclaimer. Each Data Recipient assumes any and all risk and responsibility for selection and

use of, and reliance on, any Security Data.

6. Term and Termination.

6.1. Term. The term of this agreement shall commence immediately upon the signatures of

an officer of the Data Recipient and officer of NERC and shall remain in effect until

terminated.

6.2. Termination. Any Data Recipient wishing to terminate this agreement shall notify

NERC in writing of its desire to terminate this agreement. Termination shall be effective

30 days following acknowledgment of receipt of such written notice, at which time the

Data Recipient will be prohibited from further receipt of the Security Data.

6.2.1. Termination does not excuse the Data Recipient from supplying Security Data if

required in NERC Operating Policies.

6.2.2. Termination does not excuse the Data Recipient from holding confidential any

forecast Security Data before the forecast period has passed.

7. Governmental Authority. This Agreement is subject to the laws, rules, regulations, orders and

other requirements, now or hereafter in effect, of all regulatory authorities having jurisdiction

over the Security Data, this Agreement, the Data Suppliers, and the Data Recipients. All laws,

ordinances, rules, regulations, orders and other requirements, now or hereafter in effect, of

governmental authorities that are required to be incorporated in agreements of this character are

by this reference incorporated in this Agreement.

8. Non-compliance. Data Recipients found to be not in compliance with this Agreement by NERC

or any other Data Recipient will be prohibited from further receipt of the Security Data from its

Security Coordinator(s) or the Interregional Security Network until NERC is assured, and agrees,

that the Data Recipient has resumed compliance with this Agreement. Non-compliance does not

excuse the Data Recipient from supplying Security Data if required in NERC Operating Policies,



nor does it excuse the Data Recipient from holding confidential any forecast Security Data

before the forecast period has passed.

9. Due Diligence. All signatories to this Agreement shall use due diligence to protect the

Interregional Security Network and Security Data from improper access.

10. Add succession clause to handle mergers and the like.

11. Disputes. Disputes arising over issues regarding this Agreement will be settled in accordance

with the dispute resolution procedures of the North American Electric Reliability Council or

similar procedures of its Regional Councils.

12. Governing Law. This Agreement shall in all respects be interpreted, construed and enforced in

accordance with the laws of ___________________________ (the state(s) or province(s) of the

Data Recipient), without reference to rules governing conflicts of law, except to the extent such

laws may be preempted by the laws of the United States of America, Canada, or Mexico as

applicable.

13. Integration. This agreement constitutes the entire agreement of the parties.



OFFICER OF DATA RECIPIENT

By:

Title:

Date:

OFFICER OF NERC

By:

Title:

Date:


Standards

The Performance, Interconnected Operations, and System Operator Subcommittees aredeveloping new Standards. Many of these are concepts at this point:

Subcommittee Standards

Performance • Frequency

• Reserves

• Inadvertent interchange

• Operator interface

Interconnected Operations • Security violations

• Power factor

• Operating within FCTTC

• Facility outage reporting

• Scheduling violations

System Operator Subcommittee • Operator certification

• Training course accreditation

While the Standards being developed by the Performance Subcommittee and InterconnectedOperations Subcommittee are conceptual for now, the System Operator Subcommittee’s initiatives onsystem operator certification and training course accreditation are well under way. All threesubcommittee chairs will review the standards their subcommittees are developing.

Action: Discuss:

1. Performance Subcommittee standards & Albert M. DiCaprio

2. Interconnected Operations Subcommittee standards & Walter A. Johnson

3. System Operator Subcommittee standards & Jay Lanning


Disturbance Analysis Working Group

Disturbance Analysis Working Group (DAWG) reviews of system disturbances that occurredduring the last few years found numerous inconsistencies in utility system disturbances reporting andfollow-up of the recommendations made in these reports. It concluded that the Regional Councils need toplay a more prominent role in the reporting process if these inconsistencies are to be eliminated, and thatthe NERC disturbance reporting procedure, now based on DOE criteria, should be supplemented withNERC Criteria. Therefore, DAWG recommends that Operating Policy 5F & “Emergency Operations,Disturbance Reporting” and Appendix 5F & “Reporting Requirements for Major Electric Utility SystemEmergencies” be revised (Attachment A). The proposed revisions are based on requirement and reportingprocedures in use in WSCC and MAPP. DAWG Chairman Edward C. Eakeley will lead the discussionon the revisions to Policy 5F. and Appendix 5F. He also will provide a status report on the 1996 SystemDisturbances report.

Action: Review and discuss revisions to Policy 5F and Appendix 5F and approve therevisions for Regional review.

Policy 5 && Emergency OperationsF. Disturbance Reporting

Draft: February 26, 1997 P5 661 October 18, 1996

F. Disturbance Reporting[Appendix 5F && Reporting Requirements for Major Electric Utility System Emergencies]

Criteria Introduction

Disturbances or unusual occurrences which that jeopardize the operation of the interconnectedsystems, that result, or could result, in system equipment damage, or customer interruptions, shallmust be studied in sufficient depth to increase industry knowledge of electrical interconnectionmechanics so that similar events can be prevented. It is important that tThe facts surrounding adisturbance shall be made available to system and control area operators, system managers,Reliability Councils, NERC, and regulatory agencies entitled to the information. (C.II.F.2.)

Requirements

1. Regional Reporting Procedures. Each Region shall establish and maintain a Regionalreporting procedure to facilitate preparation of a preliminary and final disturbance report.Those reports shall be submitted to the appropriate Regional and regulatory entities andNERC.

2. Analyzing disturbances. Bulk system disturbances affecting two one or more system(s)shall be promptly analyzed by the affected systems. (II.G.R.2.)

3. Disturbance reports. Based on the magnitude and duration of the disturbance or unusualoccurrence DOE and NERC disturbance reporting requirements, those systems responsiblefor investigating the incident shall provide oral, and if appropriate, a preliminary writtenreports to their Regional Council and NERC. (II.G.R.3.)

3.1. Written reports. Either a copy of the report submitted to DOE, or, if no DOE report isrequired, a copy of the NERC Preliminary Disturbance Report form, shall be submittedby the affected systems within 24 hours of the disturbance or unusual occurrence.

3.1 Oral report. An oral report shall be made to the systems Regional Council staff withintwenty-four hours after the disturbance. This oral report is in addition to the reportingrequirements of any regulatory agency having jurisdiction over the systems. (II.G.R.3.1.)

4. Notifying NERC. The NERC Disturbance Reporting requirements, shown in Appendix 5F,are the minimum requirements for reporting disturbances, unusual occurrences, and voltageand frequency excursions to NERC.

5. Notifying DOE. The U.S. Department of Energy s most recent Power System EmergencyReporting Procedures, shown in Appendix 5F are the minimum requirements for reportingdisturbances to NERC DOE. Copies of these reports shall be submitted to NERC at the sametime they are submitted to DOE. (II.G.R.4.)

6. System protection/remedial action schemes failure or misoperation. When a systemprotection or remedial action scheme failure or misoperation occurs or one that either resultsin a harmful effect or has the potential to adversely affect interconnected system operationsoccurs, the owners of the transmission system whose performance requires such schemes andthose responsible for operating the scheme shall submit to the Region(s) and NERC a short

Policy 5 && Emergency OperationsF. Disturbance Reporting

Draft: February 26, 1997 P5 662 October 18, 1996

report describing, to the extent possible, why the scheme failed or misoperated, and what isbeing done to prevent occurrence.

7. Assistance from NERC OC and DAWG. When there has been a bulk system disturbanceoccurs affecting the, the Region s OC and DAWG representatives should shall makethemselves available to the system or systems immediately affected in order to provide anyneeded assistance in the investigation and to assist in the preparation of a Final Report.(II.G.r.4.)

8. Final report recommendations. When a disturbance report results in a recommendation(s),the Region shall track such recommendation(s) to ensure it is implemented in a timelyfashion. If implementation does not occur within three years, the Region shall notify theNERC EC and OC why the recommendation(s) has not been implemented and what stepshave been taken to accelerate implementation.

Guides

1. Reporting operating problems. If an operating problem cannot be corrected quickly, theprobable duration and possible effects should be reported. (II.G.r.1.)

2. Written reports. The system or systems involved in a disturbance or unusual occurrenceshould provide a written reports following a disturbance the event. (II.G.r.2.)

2.1 Report timing. If appropriate, a preliminary written report should be available withinseveral days of the disturbance. (II.G.r.2.1.)

2.1. Reporting procedure. Reports to NERC can be sent by e-mail ([email protected]) orfacsimile (609-452-9550) using the NERC Preliminary Disturbance Report form(Appendix 5F).

2.2. Report review. If appropriate, A a final written report should be available for review byother systems so that similar events can be prevented. according to system policies.(II.G.r.2.2.)

3. Reporting $$unusual occurrences.## If, in the judgment of the system(s) involved, such an$unusual occurrence# or a “near miss” would be of interest to the electric utility industry, theincident should be reported to NERC whether or not it is reported under DOE or NERCReporting Procedures. (II.G.r.3.)

4. Reports from other systems. Information concerning bulk system disturbances in otherparts of the world can be of value in furthering the objectives of NERC. To the extent thatrelevant information can be obtained, it should be used if appropriately utilized. If such areport is obtained by NERC or any Regional member, it should be shared with all Regionalmembers. (II.G.r.5.)

Appendix 5F %% Reporting Requirements for Major ElectricUtility System Emergencies

Appendix SubsectionsA. U.S. Department of Energy Disturbance Reporting RequirementsB. NERC Disturbance Reporting RequirementsC. NERC Preliminary Disturbance ReportA. Loss of Firm System LoadsB. Voltage Reductions or Public AppealsC. Vulnerabilities That Could Impact Bulk Electric Power System Adequacy or ReliabilityD. Reports for Other Emergency Conditions or Abnormal EventsE. Fule Supply Emergencies

A. U.S. Department of Energy Disturbance Reporting Requirements

Every electric utility or other entity subject to the provisions of Section 311 of the Federal PowerAct, engaged in the generation, transmission, or distribution of electric energy for delivery and/or sale tothe public shall expeditiously report to the U.S. Department of Energy's (DOE) Emergency OperationCenter (EOC) any of the events described in the following. (A report or a part of a report required by DOEmay be made jointly by two or more entities or by a Regional Council or power pool.)

(All but one change in 1 665 is numbering)

1. Loss of Firm System Loads

1.1. Any load shedding actions resulting in the reduction of over 100 megawatts (MW) of firmcustomer load for reasons of maintaining the continuity of the bulk electric power supplysystem.

1.2. Equipment failures/system operational actions which result in the loss of firm system loadsfor a period in excess of 15 minutes, as described below:

1.2.1. Reports from entities with a previous year recorded peak load of over 3,000 MWare required for all such losses of firm loads which total over 300 MW.

1.2.2. Reports from all other entities are required for all such losses of firm loads whichtotal over 200 MW or 50% of the total customers being supplied immediatelyprior to the incident, whichever is less.

1.3. Other events or occurrences which result in a continuous interruption for three hours orlonger to over 50,000 customers, or more than 50% of the system load being servedimmediately prior to the interruption, whichever is less.

NOTE: The DOE EOC shall be notified as soon as practicable without unduly interfering with servicerestoration and, in any event, within three hours after the beginning of the interruption.

Appendix 5F && Reporting Requirements for Major Electric System Emergencies

Draft: February 26, 1997 A5F %%2 DOE Document: May 1989

2. Voltage Reductions or Public Appeals

2.1. Reports are required for any anticipated or actual system voltage reductions of threepercent or greater for purposes of maintaining the continuity of the bulk electric powersupply system.

2.2. Reports are required for any issuance of a public appeal to reduce the use of electricity forpurposes of maintaining the continuity of the bulk electric power system.

NOTE: The DOE EOC shall be notified as soon as practicable, but no later than 24 hours after initiationof the actions described in paragraph 2.2, above.

3. Vulnerabilities That Could Impact Bulk Electric Power SystemAdequacy or Reliability

3.1. Reports are required for any actual or suspected act(s) of physical sabotage (notvandalism) or terrorism directed at the bulk electric power supply system in an attempt toeither:

3.1.1. Disrupt or degrade the adequacy or service reliability of the bulk electric powersystem such that load reduction action(s) or a special operating procedure is ormay be needed.

3.1.2. Disrupt, degrade, or deny bulk electric power service on an extended basis to aspecific: (1) facility (industrial, military, governmental, private), (2) service(transportation, communications, national security), or (3) locality (town, city,country). This requirement is intended to include only major events involving thesupply of bulk power.

4. Reports for Other Emergency Conditions or Abnormal Events

4.1. Reports are required for any other abnormal emergency system operating conditions orother events which, in the opinion of the reporting entity, could constitute a hazard tomaintaining the continuity of the bulk electric power supply system. DOE has a specialinterest in actual or projected deterioration in bulk power supply adequacy and reliabilitydue to any causes. Events which may result in such deterioration include, but are notnecessarily limited to: natural disasters; failure of a large generator or transformer;extended outage of a major transmission line or cable; Federal or state actions withimpacts on the bulk electric power system.

NOTE: The DOE EOC shall be promptly notified as soon as practicable after the detection of any actualor suspected acts(s) or event(s) directed at increasing the vulnerability of the bulk electric power system. A24-hour maximum reporting period is specified in the regulations; however, expeditious reporting,especially of sabotage or suspected sabotage activities, is requested.

Appendix 5F && Reporting Requirements for Major Electric System Emergencies

Draft: February 26, 1997 A5F %%3 DOE Document: May 1989

5. Fuel Supply Emergencies

5.1. Reports are required for any anticipated or existing fuel supply emergency situation whichwould threaten the continuity of the bulk electric power supply system, such as:

5.1.2. Fuel stocks or hydroelectric project water storage levels are at 50% or less ofnormal for that time of the year, and a continued downward trend is projected.

5.1.2. Unscheduled emergency generation is dispatched causing an abnormal use of aparticular fuel type, such that the future supply or stocks of that fuel could reach alevel, which threatens the reliability or adequacy of electric service.

NOTE: The DOE EOC shall be notified as soon as practicable, or no later than three days after thedetermination is made.

B. NERC Disturbance Reporting Requirements

These disturbance reporting requirements apply to all entities using the electric transmissionsystems in North America. The requirements provide a common basis for all NERC disturbance reporting. The Operating Committee representative or his designee from the Regional Council in which adisturbance occurs shall notify NERC using the NERC Preliminary Disturbance Report form as soon aspracticable, but no later than 24 hours after initiation of the actions described in this section for any of thefollowing events.

1. The loss of bulk power transmission that significantly affects interconnection systemoperation, or

2. The occurrence of an interconnected system separation or system islanding of significanceor both, or

3. The loss of significant amount of demand (more than 200 MW or 30% of utility systemdemand), or

4. Any unusual operation or misoperationa. causing or potentially causing significant loss of demand, generation,

transmission, orb. Causing significant voltage excursions (equal to or greater than ±10%), orc. Causing significant frequency excursions (equal to or greater than 0.05Hz), ord. Causing major damage to power system components, ore. Which may be of such a nature that system operators of other electric transmission

systems might encounter a similar problem. 5. Failure or misoperation of special protection schemes, remedial action schemes, or other

operating systems that do not require system operator intervention.

NERCPrinceton Forrestal Village116-390 Village BoulevardPrinceton, NJ 08540-5731

E-mail: [email protected]: 609-452-9550Tel: 609-452-8060NERC PRELIMINARY DISTURBANCE REPORT

1. Organization filing report

2. Name of person and organization filing report:

3. Telephone number: ( ) -

4. Date and time of incident: / / Date / /Time/Zone

5. Did incident originate in your system?

6. Describe incident including appropriate: cause, equipment damage, critical services interrupted,system separation, key scheduled and actual flows prior to disturbance:

7. List generation tripped: MW total

8. Frequency excursions: Max Hz

MIN Hz

9. List transmission lines tripped (specify voltage level of each line):

FIRM INTERRUPTIBLE10. Demand tripped and MW MW

Number of customers affected Customers CustomersDemand lost in MW-Minutes MW-Min. MW-Min.

11. Restoration time Initial Final

Transmission Generation Demand

Agenda Item 20OC MeetingMarch 11&12, 1997

Reliability Assessment Subcommittee

David A. Whiteley, Chairman of the Reliability Assessment Subcommittee (RAS), will lead adiscussion on the following items.

NERC Reliability Assessment 1997%%2006 Report

The key issues that RAS is planning to address in the 1997 Reliability Assessment report will bepresented. The Engineering Committee (EC) is requested to discuss and comment on RAS s issues at thismeeting. A similar request for input from the Operating Committee (OC) will be made at this Marchmeeting. Mr. Whiteley will also report on the progress in its development of RAS procedures forconducting Regional reliability assessments along with RAS s progress on Regional interviews. RAS sprocedures will likely become part of NERC s Planning Standards and Guides following ReliabilityCriteria Subcommittee and Regional reviews.

NERC Seasonal Assessments

RAS is considering a direct role in overseeing the preparation of the NERC Seasonal Assessmentreports. This consideration is in response to recommendation 13 of the U.S. Department of Energy s(DOE) report to President Clinton on last summer s outages in WSCC, which suggested that $. . . NERC modify its periodic reporting on the reliability of the North American electricity supply anddelivery system to include more information on security . . . .# The summer and winter Seasonal Assess-ments had originally been prepared by RAS, but had become the responsibility of the OC some years ago.More recently, NERC staff has been preparing the reports based on inputs from the Regional Councils.Mr. Whiteley will address RAS s proposed role in the preparation of the Seasonal Assessment reports.

RAS Data Collection and Coordination Working Group

RAS is also considering $adopting# the NERC-EIA Data Coordination Task Force as a permanent$data collection and coordination working group,# reporting to RAS. Most recently, the Task Force wasinstrumental in streamlining the EIA-411 data collection and reporting effort, creating the NERC/DOEUnified Generator Database, and eliminating the duplication of demand and capacity data annuallyreported by the Regional Councils and their members to DOE, the Energy Information Administration(EIA), and NERC. The close working relationship and continued open dialogue between NERC andDOE/EIA have been invaluable in improving the quality and accuracy of the demand and capacity datacollected. RAS is dependent upon the EIA-411 data for a portion of its long-term reliability assessmentsand can offer its expertise in guiding the ongoing data coordination efforts with DOE/EIA.

Agenda Item 20 (cont.)OC MeetingMarch 11%12, 1997

Summary

If the EC and OC agree in concept with RAS s approach to the preparation of NERC s SeasonalAssessment reports and the management of NERC s demand and capacity data collection and reportingefforts, RAS will prepare a revised scope for itself, a new scope for the RAS $Data Collection andCoordination Working Group,# and a new NERC procedure for the development of Seasonal Assessmentreports for review and approval at the July 1997 EC and OC meetings.

Actions: a) Discuss and comment on the key reliability issues to be addressed in NERC s ReliabilityAssessment 1997%2006 report.

b) Accept in concept the Subcommittee s proposal for the preparation of NERC s $SeasonalAssessment# reports.

c) Accept in concept the Subcommittee s proposal for a data collection and coordinationworking group.

Agenda Item 23EC MeetingMarch 11%12, 1997


NERCBOARD OF TRUSTEES (BOT)

ENGINEERING COMMITTEE (EC) AND OPERATING COMMITTEE (OC)

FUTURE MEETINGS AND AGENDA INPUT DEADLINE DATES

Agenda InputMeeting Date Deadline Date Location

EC/OC March 11%12, 1997 February 14, 1997 San Diego, CaliforniaHotel Del Coronado619-435-6611

BOT May 5%6, 1997 April 11, 1997 Danvers, MassachusettsTara s Ferncroft Conference Resort508-777-2500

EC/OC July 8%9, 1997 June 13, 1997 Québec City, Québec, CanadaLe Château Frontenac418-692-3861

BOT September 15%16, 1997 August 22, 1997 Minneapolis, MinnesotaRadisson Plaza Hotel Minneapolis612-339-4900

EC/OC November 18%19, 1997 October 24, 1997 New Orleans, LouisianaSheraton New Orleans Hotel504-525-2500

BOT January 5%6, 1998 December 12, 1997 Phoenix, Arizona

EC/OC March 10%11, 1998 February 13, 1998 Salt Lake City, Utah

BOT May 4%5, 1998 April 10, 1998 New Orleans, Louisiana

EC/OC July 14%15, 1998 June 19, 1998 Vancouver, British Columbia

BOT September 14%15, 1998 August 21, 1998 Ottawa, Ontario, Canada

EC/OC November 17%18, 1998 October 23, 1998 Jacksonville, Florida

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