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N O R T H A M E R I C A N E L E C T R I C R E L I A B I L I T Y C O U N C I L Princeton Forres ta l Vi l lage, 116-390 Vil lage Boulevard, Pr inceton, New Jersey 08540-5731

Board of Trustees Meeting Minutes

October 16, 2001 Vancouver, B.C.

Chairman Richard Drouin convened a regular meeting of the North American Electric Reliability Council Board of Trustees on October 16, 2001 at 8 a.m., and a quorum was declared present. The meeting notice, agenda, and a list of attendees are attached as Exhibits A, B, and C, respectively. Consent Agenda NERC President and CEO Michehl Gent presented the consent agenda items. The Board unanimously approved the: • June 12, 2001 meeting minutes as submitted. • Recommended member replacements to serve on the Market Interface Committee and complete the

terms of the respective former members. • Composition of the 2001 Stakeholders Committee recommended slate. • Amendments to the Bylaws to accommodate Stakeholders Committee changes. • Future meeting dates and locations of June 13–14, 2002 in Minneapolis, Minnesota; October 7–8,

2002 in Charlotte, North Carolina; and February 10–11, 2003 in Scottsdale, Arizona. Operating Policies This item was deferred until the next meeting. Phase IIA Planning Standards Glenn Ross, Vice Chairman of the Planning Committee, presented the Phase IIA Planning Standards to the Board. The Board unanimously approved the following Phase IIA Planning Standards, which are attached as Exhibit D:

• System Adequacy and Security Transmission Systems: I.A. S4, M4 • System Adequacy and Security Facility Connection Requirements: I.C. S2, M2 • System Modeling Data Requirements Actual and Forecast Demands: II.D. S1-S2, M6, M11,

M12 • System Protection and Control Transmission Protection Systems: III.A. S4, M4 • System Protection and Control Underfrequency Load Shedding: III.D. S1, M1-M4 • System Protection and Control Special Protection Systems: III.F. S1-S5, M1-M6

Phone 609-452-8060 + Fax 609-452-9550 + URL www.nerc.com

Board of Trustees Minutes October 16, 2001 Organization Standards Process Manual David Hilt, NERC Compliance Director, presented the Organization Standards Process Manual (Exhibit E) to the Board for their approval. The Board: • approved the Manual subject to being revised to incorporate the details of the new weighted sector

voting model, once it is implemented, • directed that NERC seek accreditation of the Organization Standards Process by ANSI and one or

more equivalent Canadian standards association; and • adopted the Reliability and Market Interface Principles as the basis for development of NERC

Organization Standards. Organization Standards Transition Plan Due to time constraints, the Board elected not to hear this status report. Reliability Assessment 2001–2010 Chris Oakley, Reliability Assessment Subcommittee member, presented the draft Reliability Assessment 2001–2010 report to the Board, and the Board unanimously approved the report for publication. The report can be found at http://www.nerc.com/~filez/rasreports.html. Mr. Oakley also reported on the Subcommittee’s progress on the 2001 Winter Assessment report. Don Hodel suggested the Subcommittee investigate the impact of the 45% rate increase in California and include a realistic explanation in the report. Glenn Ross, Planning Committee Vice Chairman, assured the Board that is exactly what the subcommittee intends to do. The group may report back to the Board for a policy dialogue. Stakeholders Committee Report Howard Hawks, Vice Chairman of the Stakeholders Committee, reported that the Committee reached consensus on recommendations on the role of NERC in developing market interface or commercial practice standards. [NOTE: See Role of NERC in Developing Commercial Practice Standards.] Transmission Expansion: Issues and Recommendations Planning Committee Vice Chairman Glenn Ross presented the Transmission Expansion report to the Board (Exhibit F). Mr. Ross informed the Board about the Stakeholders Committee’s concerns with wording in the report on “incentive pricing.” The Board received the draft report from the Planning Committee and recommendations from the Stakeholders Committee, and asked the Transmission Adequacy Issues Task Force and Planning Committee to work with representatives of the Stakeholders Committee on the language in the report pertaining to cost recovery mechanisms. The task force is to report back to the Board in February.

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Board of Trustees Minutes October 16, 2001 Role of NERC in Developing Commercial Practice Standards Based on the strong recommendation of the Stakeholders Committee for a single organization to develop both reliability standards and wholesale electric business practice standards, the Board approved a resolution that NERC: 1. Take all necessary steps to become the single organization in North America to develop both

reliability standards and wholesale electric business practice standards through a fair, open, balanced, and inclusive process, and to file such standards with FERC and appropriate government agencies in Canada.

2. Actively solicit cooperation, collaboration, and support from Canadian and U.S. government entities

to establish NERC as the single organization in North America for the development of reliability standards and wholesale electric business practice standards.

3. Take immediate action to adopt and implement the six Initial Recommendations of the Standing

Committees Representation Task Force contained in Board Agenda Item 22. 4. Facilitate jointly with interested trade associations; federal, state, and provincial regulators; and

other stakeholder organizations an open and inclusive process to achieve consensus on the definitions and attributes of the functions necessary for the development of wholesale electric industry standards and practices, and on a course of action to institute such capabilities.

5. Interface with state and provincial regulators to address retail operational issues that may affect

wholesale electric operations. 6. Build on the results of activities to date regarding the new Reliability Model and new Organization

Standards Development Process. 7. Recommend that FERC use the Electronic Scheduling Collaborative report, which has already been

submitted to FERC, as the basis for a notice of proposed rulemaking on electric business practice standards.

8. Urge FERC to make use of the Electronic Scheduling Collaborative, which will use the new sector

weighted voting model approved by the NERC Board, for further development of wholesale electric business practice standards, including standards necessary for certain aspects of RTO design such as congestion management and ancillary services.

9. Commit to continuing to support the work of the ESC until such time as an industry consensus is

achieved on how to develop wholesale electric business practice standards within the NERC framework.

John A. Anderson, ELCON observer, voiced a concern about whether the Electronic Scheduling Collaborative was sufficiently balanced for NERC to endorse its continued use. The Board included the phrase, “which will use the new sector weighted voting model approved by the NERC Board,” in paragraph 8 of the resolution to address that concern.

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Board of Trustees Minutes October 16, 2001 Independence of Security Coordinators The Board of Trustees unanimously approved a resolution that NERC take the following actions to assure that the Security Coordinator function is performed independently from wholesale and retail merchant functions: 1. Write to FERC detailing the current status of the independence of our Security Coordinators,

supporting the independence principles of Order 2000, and informing the Federal Energy Regulatory Commission (FERC) of actions NERC intends to take during the transition to RTOs.

2. Ask the Security Coordinators to provide NERC with an acknowledgement of their intent to make the

transition to an RTO and a timeline for doing so. For those Security Coordinators that will not transition to RTOs, ask them to submit a plan for how they will otherwise meet the goal of having the Security Coordinator function be wholly independent of the retail and wholesale merchant functions.

3. Instruct the NERC Director of Compliance to include procedures to evaluate how Security Coordinators

are assuring that their operations are independent of those who participate in the marketplace as a part of his ongoing audits of Security Coordinators. The Director of Compliance should also place a high priority on investigating specific complaints received by NERC where a Security Coordinator is alleged to have operated in a manner inconsistent with functioning independently of market participants. Based on those audits and investigations, the Director of Compliance should make recommendations to the Board of Trustees, as appropriate, for compliance actions, changes to the Security Coordinator Standards of Conduct, and referrals to the FERC and other governmental authorities.

Composition of the NERC Standing Committees The Board:

1. Endorsed the six Initial Recommendations of the Standing Committees Representation Task Force

regarding the composition and voting of the NERC standing committees. 2. Requested the Standing Committees Representation Task Force to work with the three standing

committees to finalize the details and implement the Initial Sectors and Criteria Model and weighted voting procedures by January 15, 2002, and to make conforming changes to the Organization and Procedures for NERC Standing Committees and the Organization Standards Process Manual.

3. Directed the standing committees to add two ISO/RTO representatives to each of the standing

committees until the Initial Sectors and Criteria Model and weighted voting procedures have been implemented.

Directed the task force to complete its final report for the Board’s February 2002 meeting. Summary of Committees Survey of Key Issues Due to time constraints, the Board elected not to discuss this item. Finance and Audit Committee Report Charles Henry, Finance and Audit Committee Chairman, presented the proposed 2002 Budget to the Board. Mr. Henry reported that the Committee had accepted recommendations from the Cost Allocation Subcommittee, and that he had met with MAPP and NPCC to discuss their concerns with the budget. He

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Board of Trustees Minutes October 16, 2001 assured the Board that the Finance and Audit Committee will remain proactive on cost overruns and the committee will look at projects that can be moved out of the budget and into self-funded areas. The Board unanimously approved the proposed budget of $12,507,244 and Assessments of $12,440,442. Comments by Observers Several observers commended the Board for an excellent meeting. In addition, Hans Konow of CEA emphasized the need for NERC to occupy both reliability and business practice standards. Chris Forbes of EEI stated EEI was very supportive of NERC taking on both reliability and business practice standards and urged NERC to speed up its efforts in light of the EISB proposal. Special Recognition Howard Hawks, Stakeholders Committee Vice Chairman, suggested that the Board and Stakeholders Committee present a resolution of appreciation to Gary Neale, Stakeholders Committee Chairman and Past Chairman of the Board of Trustees, for all that he had done on behalf of the organization. The Board wholeheartedly agreed. Adjournment There being no further business to be brought before the Board, Chairman Drouin adjourned the meeting at 10:56 a.m.

David N. Cook Secretary

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Exhibit A

N O R T H A M E R I C A N E L E C T R I C R E L I A B I L I T Y C O U N C I L Pr ince ton For res t a l V i l l age , 116-390 Vi l l age Bou leva rd , P r ince ton , New Je r sey 08540-5731

July 24, 2001

TO: BOARD OF TRUSTEES Ladies and Gentlemen: Board of Trustees Meetings

October 15–16, 2001

The next NERC Board of Trustees meetings will be October 15–16, 2001 in Vancouver, British Columbia at the Delta Vancouver Suites, 550 West Hastings Street, Vancouver, B.C., Canada. The hotel is about 25 minutes from Vancouver International Airport. There is no direct shuttle to the hotel, and taxis cost about $25–30 (Canadian).

To make your room reservation, call Delta reservations at 800-268-1133 or the hotel directly at 604-689-8188. NERC’s room block is listed under NERC, and the rate is $195 (Canadian) for single/double occupancy. The hotel has set September 21, 2001 as the cut-off for room reservations. If you want me to make your sleeping room reservation, please e-mail the details to me ([email protected]). For your information, a summary of all meetings follows:

October 15, 2001 Regional Managers and Technical Steering Committee 8 a.m.–noon Board Orientation Session and Lunch 10 a.m.–1 p.m. Stakeholders Committee 1–5 p.m. Board Committees: Human Resources and Compensation 1–2 p.m. Governance and Nominating 2:30–3:30 p.m. Finance and Audit 4–5 p.m. Group Reception and Dinner 6–8:30 p.m. October 16, 2001 Board of Trustees 8 a.m.–1 p.m.

The meetings will take place at the Centre for Dialogue at Simon Fraser University, which has walk-through access to the Delta hotel. Dress is casual for all meetings and the dinner. A meeting registration form is enclosed for your convenience. Please call me if you have any questions. Sincerely,

Julie Morgan

Enclosure Executive Assistant


mailto:[email protected]

Exhibit B

N O R T H A M E R I C A N E L E C T R I C R E L I A B I L I T Y C O U N C I L

Princeton Forrestal Vil lage, 116-390 Vil lage Boulevard , Pr inceton, New Jersey 08540-5731

Board of Trustees Meeting

October 16, 2001 8 a.m.–1 p.m. Vancouver, B.C. Delta Vancouver Suites

Agenda

Introductions and Chairman’s Remarks Consent Agenda 1. Minutes of June 12, 2001 Meeting 2. Membership Appointments for NERC Standing Committees 3. Approval of Composition of Stakeholders Committee 4. Bylaws Changes to Accommodate Stakeholders Committee Changes 5. Future Meetings Informational 6. Treasurer’s Report 7. Agreements for Regional Compliance and Enforcement Programs 8. Projects Status Approved and Pending 9. National Transmission Grid Study 2001 10. Reliability Legislation 11. Compliance Enforcement Program 12. FERC Discussion of RTO Progress Standards 13. Operating Policies Approve

a. Appendix 1D Time Error Correction Procedures 14. Phase IIA Planning Standards Approve

a. I.A. S4, M4 Transmission Systems b. I.C. S2, M2 Facility Connection Requirements c. II.D. S1–S2, M6, M11, M12 Actual and Forecast Demands d. III.A. S4, M4 Transmission Protection Systems e. III.D. S1, M1–M4 Underfrequency Load Shedding f. III.F. S1–S5, M1–M6 Special Protection Systems

15. Organization Standards Process Manual Approve 16. Organization Standards Transition Plan Reliability Reports 17. Reliability Assessment 2001–2010 Approve 18. Winter Assessment Schedule and Process Informational 19. Transmission Expansion: Issues and Recommendations Approve BREAK


ftp://www.nerc.com/pub/sys/all_updl/docs/bot/Agenda-Items-1001/Item1-bot0601m.pdf

NERC Board of Trustees Agenda October 16, 2001 Policy Discussions 20. Role of NERC in Developing Commercial Practice Standards 21. Independence of Security Coordinators 22. Composition of the NERC Standing Committees Approve 23. Summary of Committees Survey of Key Issues Committee Reports 24. Finance and Audit

a. 2002 Budget Approve 25. Corporate Governance and Nominating 26. Human Resources and Compensation 27. Stakeholders 28. Standing Committees

a. Market Interface Committee Meeting Highlights b. Operating Committee Meeting Highlights c. Planning Committee Meeting Highlights

ftp://www.nerc.com/pub/sys/all_updl/docs/bot/Agenda-Items-1001/Item28a-mic0109h.pdf

ftp://www.nerc.com/pub/sys/all_updl/docs/bot/Agenda-Items-1001/Item28b-oc0701h.pdf

ftp://www.nerc.com/pub/sys/all_updl/docs/bot/Agenda-Items-1001/Item28c-pc0107h.pdf

Exhibit C

List of Attendees Board of Trustees Meeting

October 16, 2001

Board Members Richard Drouin, Chairman Thomas W. Berry, Vice Chairman John Q. Anderson Michehl R. Gent James M. Goodrich

Charles J. Henry Donald P. Hodel Sharon L. Nelson William H. White

Attendees

John Anderson, ELCON Bruce Balmat, MAAC Paul Barber, MIC Chairman Don Benjamin, NERC Joel Bladow, WAPA Terry Boston, TVA Richard Bulman, MAPP Jim Byrd, TXU Paul Cafone, MAAC Gerry Cauley, NERC John Conti, DOE Joe Conner, NERC David Cook, NERC Derek Cowbourne, OC Vice Chairman Bob Cummings, NERC Charles Durkin, NPCC Brant Eldridge, ECAR Dennis Eyre, WSCC Mark Fidrych, WAPA (OC Vice Chairman) Chris Forbes, EEI Lindy Funkhouser, Arizona Residental Utility Consumer Office Heather Gibbs, NERC Steve Gilliland, Duke Energy North America Dave Goulding, Canada Mike Greene, SHC Chairman Phil Harris, MAAC Howard Hawks, SHC Vice Chairman Dave Hilt, NERC Richard Ingersoll, Ingersoll Energy Consultants Wally Johnson, PEPCO (CS Chairman) Sam Jones, ERCOT Hans Konow, CEA Dale Landgren, American Transmission Co.

Donald LeKang, FERC Bill Marks, Mirant Steve McCoy, CAISO (PS Vice Chairman) Marty Mennes, FRCC (MIC Vice Chairman) Bob Modray, National Energy Board Julie Morgan, NERC Patrick Mulchay, ECAR Dave Nevius, NERC Chris Oakley, West Kootenay Power (RAS) Phil Park, Powerex Dave Penn, APPA Armando J. Perez, CAISO Harlow Peterson, Salt River Project Sonny Popowsky, Pennsylvania Office of Consumer Advocate Vann Prater, Dynegy William Reinke, SERC Glenn Ross, PC Vice Chairman Ed Schwerdt, NPCC Marsha Smith, NARUC (Idaho PUC) Dejan J. Sobajic, EPRI John Stauffacher, ERCOT Virginia Sulzberger, NERC Ron Threlkeld, B.C. Hydro (Canada) John Twitchell, Mirant Ken Wiley, FRCC

Exhibit D

REVISED PHASE IIA STANDARDS, MEASUREMENTS,

AND COMPLIANCE TEMPLATES

North American Electric Reliability Council

NERC Board of Trustees

October 16, 2001

Compliance Templates I.A. NERC Planning Standards

June 15, 2001 Version Approved by Planning Committee: September 17, 2001. Approved by NERC Board of Trustees: October 16, 2001 1.

Brief Description: System performance following extreme events resulting in the loss of two or more bulk system elements.

Category Assessments Section I. System Adequacy and Security A. Transmission Systems Standard S4. The interconnected transmission systems shall be evaluated for the risks and consequences

of a number of each of the extreme contingencies that are listed under Category D of Table I (attached).

Measurement M4. Entities responsible for the reliability of the interconnected transmission systems shall

assess the risks and system responses for Standard S4 as defined in Category D of Table I (attached).

Assessment Requirements Entities responsible for the reliability of the interconnected transmission systems (e.g., transmission owners, independent system operators (ISOs), regional transmission organizations (RTOs), or other groups responsible for planning the bulk electric systems) shall annually assess the performance of their systems in meeting Standard S4. Valid assessments shall include the attributes listed below, and as more fully described in the following paragraphs: 1. Assessments shall be conducted for near-term (years one through five) planning

horizons. 2. Assessments shall be supported by a current or past study that addresses the plan year

being assessed.

System performance assessments based on system simulation testing shall evaluate system conditions of Table I Category D, with all projected firm transfers modeled. Assessments shall consider all contingencies applicable to Category D, but shall simulate and evaluate only those that would produce the more severe system results or impacts. The rationale for the contingencies selected for evaluation shall be available as supporting information and shall include an explanation of why the remaining simulations would produce less severe system results. Assessments shall include the effects of existing and planned facilities, including reactive power resources, and shall include the effects of existing and planned protection systems and control devices, including any backup or redundant protection systems.



Assessments shall consider the planned (including maintenance) outage of any bulk electric equipment (including protection systems or their components) at those demand levels for which planned (including maintenance) outages are performed when evaluating the effects of Category D events. Assessments shall be conducted annually and shall cover critical system conditions and study years as deemed appropriate by the responsible entity. They shall be conducted for near-term (years one through five) planning horizons. Simulation testing of the systems need not be conducted annually if changes to system conditions do not warrant such analyses.

Corrective Plan Requirements None required. Reporting Requirements The documentation of results of these reliability assessments and mitigation measures shall annually be provided to the entities’ respective NERC Region(s), as required by the Region. Each Region, in turn, shall annually provide a summary (per Standard I.B. S1. M1) of its Regional reliability assessments to the NERC Planning Committee (or its successor).

Applicable to Entities responsible for the reliability of interconnected transmission systems. Items to be Measured Assessments of system performance for extreme events (more severe than in M3) resulting in loss of two or more bulk system elements. Timeframe Annually. Levels of Non-Compliance

Level 1 A valid assessment for the near-term planning horizon is not available. Level 2 Not applicable. Level 3 Not applicable. Level 4 Not applicable.

Compliance Monitoring Responsibility Regions.



Comments on Compliance Rating

Compliance Templates I. A. NERC Planning Standards Guides


I. System Adequacy and Security A. Transmission Systems

G1. The planning, development, and maintenance of transmission facilities should be

coordinated with neighboring systems to preserve the reliability benefits of interconnected operations.

G2. Studies affecting more than one system owner or user should be conducted on a joint

interconnected system basis. G3. The interconnected transmission systems should be designed and operated such that

reasonable and foreseeable contingencies do not result in the loss or unintentional separation of a major portion of the network.

G4. The interconnected transmission systems should provide flexibility in switching

arrangements, voltage control, and other protection system measures to ensure reliable system operation.

G5. The assessment of transmission system capability and the need for system enhancements

should take into account the maintenance outage plans of the transmission facility owners. These maintenance plans should be coordinated on an intra- and interregional basis.

G6. The interconnected transmission systems should be planned to avoid excessive

dependence on any one transmission circuit, structure, right-of-way, or substation.

G7. Reliability assessments should examine post-contingency steady-state conditions as well as stability, overload, cascading, and voltage collapse conditions. Pre-contingency system conditions chosen for analysis should include contracted firm (non-recallable reserved) transmission services.

G8. Annual updates to the transmission assessments should be performed, as appropriate, to

reflect anticipated significant changes in system conditions.

G9. Extreme contingency evaluations should be conducted to measure the robustness of the interconnected transmission systems and to maintain a state of preparedness to deal effectively with such events. Although it is not practical (and in some cases not possible) to construct a system to withstand all possible extreme contingencies without cascading, it is desirable to control or limit the scope of such cascading or system instability events and the significant economic and social impacts that can result.

G10. It may be appropriate to conduct the extreme contingency assessments on a coordinated

intra- or interregional basis so that all potentially affected entities are aware of the possibility of cascading or system instability events.

NERC Planning Standards I. System Adequacy and Security A. Transmission Systems


Table I. Transmission Systems Standards — Normal and Contingency Conditions

Contingencies

System Limits or Impacts

Category

Initiating Event(s) and Contingency Element(s)

Elements

Out of Service

Thermal Limits

Voltage Limits

System Stable

Loss of Demand or Curtailed Firm Transfers

Cascading

c

Outages A - No Contingencies

All Facilities in Service

None

Applicable

Rating a (A/R)

Applicable

Rating a (A/R)

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:

1. Generator 2. Transmission Circuit 3. Transformer

Loss of an Element without a Fault.

Single Single Single Single

A/R A/R A/R A/R

A/R A/R A/R A/R

Yes Yes Yes Yes

No b No b No b No b

No No No No

B - Event resulting in the loss of a single element.

Single Pole Block, Normal Clearing

f:

4. Single Pole (dc) Line

Single

A/R

A/R

Yes

Nob

No

SLG Fault, with Normal Clearing

f:

1. Bus Section 2. Breaker (failure or internal fault)

Multiple Multiple

A/R A/R

A/R A/R

Yes Yes

Planned/Controlledd Planned/Controlledd

No No

SLG or 3Ø Fault, with Normal Clearing

f, Manual System Adjustments,

followed by another SLG or 3Ø Fault, with Normal Clearingf:

3. Category B (B1, B2, B3, or B4) contingency, manual system adjustments, followed by another Category B (B1, B2, B3, or B4) contingency

Multiple

A/R

A/R

Yes

Planned/Controlledd

No

Bipolar Block, with Normal Clearing

f:

4. Bipolar (dc) Line

Fault (non 3Ø), with Normal Clearingf:

5. Any two circuits of a multiple circuit towerlineg

Multiple Multiple

A/R A/R

A/R A/R

Yes Yes


No No

C - Event(s) resulting in the loss of two or more (multiple) elements.

SLG Fault, with Delayed Clearing

f (stuck breaker or protection system

failure): 6. Generator 8. Transformer 7. Transmission Circuit 9. Bus Section

Multiple Multiple

A/R A/R

A/R A/R

Yes Yes


No No

NERC Planning Standards I. System Adequacy and Security A. Transmission Systems


D e - Extreme event resulting in two or more (multiple) elements removed or cascading out of service

3Ø Fault, with Delayed Clearing

f (stuck breaker or protection system

failure): 1. Generator 3. Transformer 2. Transmission Circuit 4. Bus Section

3Ø Fault, with Normal Clearingf:

5. Breaker (failure or internal fault) Other:

6. Loss of towerline with three or more circuits 7. All transmission lines on a common right-of way 8. Loss of a substation (one voltage level plus transformers) 9. Loss of a switching station (one voltage level plus transformers)

10. Loss of all generating units at a station 11. Loss of a large load or major load center 12. Failure of a fully redundant special protection system (or remedial

action scheme) to operate when required 13. Operation, partial operation, or misoperation of a fully redundant

special protection system (or remedial action scheme) in response to an event or abnormal system condition for which it was not intended to operate

14. Impact of severe power swings or oscillations from disturbances in another Regional Council.

Evaluate for risks and consequences. § May involve substantial loss of customer demand and generation in a

widespread area or areas. § Portions or all of the interconnected systems may or may not achieve a new,

stable operating point. § Evaluation of these events may require joint studies with neighboring systems.

a) Applicable rating (A/R) refers to the applicable normal and emergency facility thermal rating or system voltage limit as determined and consistently applied by the system or

facility owner. Applicable ratings may include emergency ratings applicable for short durations as required to permit operating steps necessary to maintain system control. All ratings must be established consistent with applicable NERC Planning Standards addressing facility ratings.

b) Planned or controlled interruption of electric supply to radial customers or some local network customers, connected to or supplied by the faulted element or by the affected area, may occur in certain areas without impacting the overall security of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of contracted firm (non-recallable reserved) electric power transfers.

c) Cascading is the uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread service interruption which cannot be restrained from sequentially spreading beyond an area predetermined by appropriate studies.

d) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted firm (non-recallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems.

e) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated.

f) Normal clearing is when the protection system operates as designed and the fault is cleared in the time normally expected with proper functioning of the installed protection systems. Delayed clearing of a fault is due to failure of any protection system component such as a relay, circuit breaker, or current transformer (CT), and not because

of an intentional design delay. g) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station entrance, river crossings) in accordance with Regional

exemption criteria.

Compliance Templates I.C. NERC Planning Standards


Brief Description Coordination of plans for new generation, transmission, and end-user facilities.

Category Assessment Section I. System Adequacy and Security C. Facility Connection Requirements Standard S2. Generation, transmission, and electricity end-user facilities, and their modifications, shall

be planned and integrated into the interconnected transmission systems in compliance with NERC Planning Standards, applicable Regional, subregional, power pool, and individual system planning criteria and facility connection requirements.

Measurement M2. Those entities responsible for the reliability of the interconnected transmission systems and

those entities seeking to integrate generation facilities, transmission facilities, and electricity end-user facilities shall coordinate and cooperate on their respective assessments to evaluate the reliability impact of the new facilities and their connections on the interconnected transmission systems and to ensure compliance with NERC Planning Standards and applicable Regional, subregional, power pool, and individual system planning criteria and facility connection requirements.

The entities involved shall present evidence that they have cooperated on the assessment of

the reliability impacts of new facilities on the interconnected transmission systems. While these studies may be performed independently, the results shall be jointly evaluated and coordinated by the entities involved. Assessments shall include steady-state, short-circuit, and dynamics studies as necessary to evaluate system performance under Standard I.A.

Documentation of these assessments shall include study assumptions, system performance,

alternatives considered, and jointly coordinated recommendations. This documentation shall be retained for three years and shall be provided to the Regions and NERC on request (within 30 days).

Applicable to • Entities responsible for the reliability of the interconnected transmission systems. • Entities seeking to integrate generation, transmission, and end-users facilities into the interconnected

transmission systems. Items to be Measured Assessment of the reliability impacts of new facilities.

Timeframe On request (within 30 days).

Compliance Templates I.C. NERC Planning Standards


Levels of Non-Compliance Level 1 Assessments of the impacts of new facilities were provided, but were incomplete in one or more

requirements of Measurement M2. Level 2 Not applicable. Level 3 Not applicable. Level 4 Assessments of the impacts of new facilities were not provided. Compliance Monitoring Responsibility Regions. Reviewer Comments on Compliance Rating

Compliance Templates I.C. NERC Planning Standards Guides


I. System Adequacy and Security A. Facility Connection Requirements

G1. Inspection requirements for connected facilities or new facilities to be connected should be included in the facility connection requirements documentation.

G2. Notification of new facilities to be connected, or modifications of existing facilities

already connected to the interconnected transmission systems should be provided to those responsible for the reliability of the interconnected transmission systems as soon as feasible to ensure that a review of the reliability impact of the facilities and their connections can be performed and that the facilities are placed in service in a timely manner.

G3. Use of common data and modeling techniques is encouraged.

Compliance Templates II.D. NERC Planning Standards


Brief Description Treatment of nonmember demand data and how uncertainties are addressed in the forecasts of demand and net energy for load.

Category Documentation Section II. System Modeling Data Requirement D. Actual and Forecast Demands Standard S1. Actual demands and net energy for load data shall be provided on an aggregated Regional,

subregional, power pool, individual system, or load serving entity basis. Actual demand data on a dispersed substation basis shall be supplied when requested.

Forecast demands and net energy for load data shall be developed and maintained on an

aggregated Regional, subregional, power pool, individual system, or load serving entity basis. Forecast demand data shall also be developed on a dispersed substation basis.

Measurement M6. The actual and forecast demand data reported on either an aggregated or dispersed basis

shall:

a) indicate whether the demand data of nonmember entities within an area or Region are included, and

b) address assumptions, methods, and the manner in which uncertainties are treated in the

forecasts of aggregated peak demands and net energy for load.

Full compliance requires items (a) and (b) to be addressed as described in the reporting procedures developed for Measurement M1 of this Standard II.D. Current information on items a) and b) shall be reported to NERC, the Regions, and those entities responsible for the reliability of the interconnected transmission systems on request (within 30 days).

Applicable to Entities required by the Region to report actual and forecast demand data. Items to be Measured a) Treatment of actual and forecast demand data of nonmember entities. b) Information on assumptions, methods, and how uncertainties are addressed in the forecasts of demand

and net energy for load data. Timeframe On request (within 30 days).



Levels of Non-Compliance

Level 1 Information on items a) or b) was not provided. Level 2 Information on items a) and b) was not provided. Level 3 Not applicable. Level 4 Not applicable.

Compliance Monitoring Responsibility Regions. Reviewer Comments on Compliance Rating



Brief Description Interruptible demands and direct control load management data to be made known to system operators and security center coordinators.

Category Data Section II. System Modeling Data Requirements D. Actual and Forecast Demands Standard S2. Controllable demand-side management (interruptible demands and direct control load

management) programs and data shall be identified and documented. Measurement M11. The amount of interruptible demands and direct control load management shall be made

known to system operators and security center coordinators on request.

Full compliance requires the reporting of this data to system operators and security center coordinators within 30 days of a request.

Applicable to Entities responsible for the reliability of the interconnected transmission systems. Items to be Measured Reporting of interruptible demands and direct control load management data to system operators and security center coordinators. Timeframe On request (within 30 days). Levels of Non-Compliance

Level 1 Interruptible demands and direct control load management data were provided to system operators and security center coordinators, but were incomplete. Level 2 Not applicable. Level 3 Not applicable. Level 4 Interruptible demands and direct control load management data were not provided to system operators and security center coordinators.




Reviewer Comments on Compliance Rating



Brief Description Documentation of the method of accounting for the effects of controllable demand-side management in demand and energy forecasts.

Category Documentation Section II. System Modeling Data Requirements D. Actual and Forecast Demands Standard S2. Controllable demand-side management (interruptible demands and direct control load

management) programs and data shall be identified and documented. Measurement M12. Forecasts shall clearly document how the demand and energy effects of demand-side

management programs (such as conservation, time-of-use rates, interruptible demands, and direct control load management) are addressed.

Information detailing how demand-side management measures are addressed in the forecasts of peak demand and annual net energy for load shall be included in the data reporting procedures of Measurement M1 of this Standard II.D. Documentation on the treatment of demand-side management programs shall be available to NERC on request (within 30 days).

Applicable to Entities required by the Region to report actual and forecast demand data. Items to be Measured How the effects of demand-side management programs are addressed in the forecasts of peak demand and annual net energy for load. Timeframe On request (within 30 days). Levels of Non-Compliance

Level 1 Documentation on the treatment of demand-side management programs in the demand and energy forecasts was provided, but was incomplete. Level 2 Not applicable. Level 3 Not applicable. Level 4 Documentation on the treatment of demand-side management programs in the demand and energy forecasts was not provided.




Compliance Templates III.A. NERC Planning Standards


Brief Description Transmission protection system maintenance and testing. Category Documentation and implementation Section III. System Protection and Control A. Transmission Protection Systems Standard S4. Transmission protection system maintenance and testing programs shall be developed and

implemented. Measurement M4. Transmission protection system owners shall have a protection system maintenance and

testing program in place. This program shall include protection system identification, schedule for protection system testing, and schedule for protection system maintenance.

Documentation of the program and its implementation shall be provided to the appropriate Regions and NERC on request (within 30 days).

Applicable to Transmission protection system owner. Items to be Measured Documentation and implementation of transmission protection system maintenance and testing program. Timeframe On request (within 30 days). Levels of Non-Compliance Level 1

Documentation of the maintenance and testing program was provided, but records indicate that implementation was not on schedule.

Level 2

Documentation of the maintenance and testing program was incomplete, but records indicate implementation was on schedule.

Level 3

Documentation of the maintenance and testing program was incomplete, and records indicate implementation was not on schedule.

Level 4 No documentation of the maintenance and testing program or its implementation was provided.


Compliance Templates III.A. NERC Planning Standards



Compliance Templates III. System Protection and Control NERC Planning Standards D. Underfrequency Load Shedding


Introduction A coordinated automatic underfrequency load shedding (UFLS) program is required to help preserve the security of the generation and interconnected transmission systems during major declining system frequency events. Such a program is essential to minimize the risk of total system collapse, protect generating equipment and transmission facilities against damage, provide for equitable load shedding (interruption of electric supply to customers), and help ensure the overall reliability of the interconnected systems. Load shedding resulting from a system underfrequency event should be controlled so as to balance generation and customer demand (load), permit rapid restoration of electric service to customer demand that has been interrupted, and when necessary re-establish transmission interconnection ties.

Compliance Templates III.D. NERC Planning Standards


Brief Description Development and documentation of Regional underfrequency load shedding (UFLS) programs coordinated within and among Regions.

Category Process, data, and assessment Section III. System Protection and Control D. Underfrequency Load Shedding

Standards S1. A Regional UFLS program shall be planned and implemented in coordination with other

UFLS programs, if any, within the Region and, where appropriate, with neighboring Regions. The Regional UFLS program shall be coordinated with generation control and protection systems, undervoltage and other load shedding programs, Regional load restoration programs, and transmission protection and control systems.

Measurement M1. Each Region shall develop, coordinate, and document a Regional UFLS program, which

shall include the following: a. Requirements for coordination of UFLS programs within the subregions, Region,

and, where appropriate, among Regions. b. Design details including size of coordinated load shedding blocks (% of connected

load), corresponding frequency set points, intentional delays, related generation protection, tie tripping schemes, islanding schemes, automatic load restoration schemes, or any other schemes that are part of or impact the UFLS programs.

c. A Regional UFLS program database. This database shall be updated as specified in the Regional program (but at least every five years) and shall include sufficient information to model the UFLS program in dynamic simulations of the interconnected transmission systems.

d. Technical assessment and documentation of the effectiveness of the design and implementation of the Regional UFLS program. This technical assessment shall be conducted periodically and shall (at least every five years or as required by changes in system conditions) include, but not be limited to:

1. A review of the frequency set points and timing, and 2. Dynamic simulation of possible disturbance that cause the Region or portions

of the Region to experience the largest imbalance between demand (load) and generation.

e. Determination, as appropriate, of maintenance, testing, and calibration requirements by member systems.

Documentation of each Region’s UFLS program and its database information shall be current and provided to NERC on request (within 30 days). Documentation of the current technical assessment of the UFLS program shall also be provided to NERC on request (within 30 days).

Applicable to Regions.



Items to be Measured The documentation and coordination of Regional UFLS programs. Timeframe On request (within 30 days) for the program, database, and results of technical assessments. Levels of Non-Compliance

Level 1 Documentation demonstrating the coordination of the Regional UFLS program was incomplete in one or more requirements of Measurement M1. Level 2 Not applicable. Level 3 Not applicable. Level 4 Documentation demonstrating the coordination of the Regional UFLS program was not provided.

Compliance Monitoring Responsibility NERC. Reviewer Comments on Compliance Rating



Brief Description Assuring consistency of entity UFLS programs with Regional UFLS requirements.

Category Assessment Section III. System Protection and Control

D. Underfrequency Load Shedding Standard S1. A Regional UFLS program shall be planned and implemented in coordination with other


Measurement M2. Those entities owning or operating an UFLS program shall ensure that their programs are

consistent with Regional UFLS program requirements as specified in Measurement M1. Such entities shall provide and annually update their UFLS data as necessary for the Region to maintain and update an UFLS program as specified in Measurement M1.

The documentation of an entity’s UFLS program shall be provided to the Region on request (within 30 days).

Applicable to Entities owning, operating, or required (by the Regions) to have an UFLS program. Items to be Measured Consistency of entity’s UFLS program with Regional UFLS requirements. Timeframe On request (within 30 days). Levels of Non-Compliance

Level 1 Evaluations of entity UFLS programs for consistency with the Regional UFLS program were incomplete in one or more requirements of Measurement M1. Level 2 Not applicable. Level 3 Not applicable. Level 4 Evaluations of entity UFLS programs for consistency with the Regional UFLS program were not provided.






Brief Description Implementation and documentation of UFLS equipment maintenance program.

Category Process Section III. System Protection and Control D. Underfrequency Load Shedding Standard S1. A Regional UFLS program shall be planned and implemented in coordination with other


Measurement M3. UFLS equipment owners shall have an UFLS equipment maintenance and testing program

in place. This program shall include UFLS equipment identification, the schedule for UFLS equipment testing, and the schedule for UFLS equipment maintenance.

These programs shall be maintained and documented, and the results of implementation shall be provided to the Regions and NERC on request (within 30 days).

Applicable to Entities owning, operating, or required (by the Regions) to have UFLS equipment. Items to be Measured Each entity’s UFLS equipment maintenance program. Timeframe On request (within 30 days). Levels of Non-Compliance

Level 1 Documentation of the UFLS equipment maintenance and testing program was provided, but records indicate that implementation was not on schedule . Level 2 Documentation of the UFLS equipment maintenance and testing program was incomplete, but records indicate implementation was on schedule. Level 3 Documentation of the UFLS equipment maintenance and testing program was incomplete, and records indicate implementation was not on schedule. Level 4 No documentation of the UFLS equipment maintenance or testing program or its implementation was provided.






Brief Description Analysis and documentation of UFLS program performance. Category Assessment Section III. System Protection and Control

D. Underfrequency Load Shedding Standard S1. A Regional UFLS program shall be planned and implemented in coordination with other


Measurement M4. Those entities owning or operating UFLS programs shall analyze and document their UFLS

program performance in accordance with Standard III.D. S1-S2, M1, including the performance of UFLS equipment and program effectiveness following system events resulting in system frequency excursions below the initializing set points of the UFLS program. The analysis shall include, but not be limited to:

1) A description of the event including initiating conditions 2) A review of the UFLS set points and tripping times 3) A simulation of the event 4) A summary of the findings

Documentation of the analysis shall be provided to the Regions and NERC on request 90 days after the system event.

Applicable to Entities owning, operating, or required (by the Regions) to have an UFLS program. Items to be Measured Analysis of UFLS program performance for underfrequency events below the UFLS set points. Timeframe On request 90 days after the system event. Levels of Non-Compliance

Level 1 Analysis of UFLS program performance following an actual underfrequency event below the UFLS set point(s) was incomplete in one or more requirements of Measurement M4. Level 2 Not applicable. Level 3 Not applicable.



Level 4 Analysis of UFLS program performance following an actual underfrequency event below the UFLS set point(s) was not provided.


Compliance Templates III.D. NERC Planning Standards Guides


III. System Protection and Control D. Underfrequency Load Shedding

G1. The UFLS programs should occur in steps related to frequency or rate of frequency decay as determined from system simulation studies. These studies are critical to coordinate the amount of load shedding necessary to arrest frequency decay, minimize loss of load, and permit timely system restoration.

G2. The UFLS programs should be coordinated with generation protection and control,

undervoltage and other load shedding programs, Regional load restoration programs, and transmission protection and control.

G3. The technical assessment of UFLS programs should include reviews of system design

and dynamic simulations of disturbances that would cause the largest expected imbalances between customer demand and generation. Both peak and off-peak system demand levels should be considered. The assessments should predict voltage and power transients at a widespread number of locations as well as the rate of frequency decline, and should reflect the operation of underfrequency sensing devices. Potential system separation points and resulting system islands should be determined.

G4. Except for qualified automatic isolation plans, the opening of transmission

interconnections by underfrequency relaying should be considered only after the coordinated load shedding program has failed to arrest system frequency decline and intolerable system conditions exist.

G5. A generation-deficient entity may establish an automatic islanding plan in lieu of

automatic load shedding, if by doing so it removes the burden it has imposed on the transmission systems. This islanding plan may be used only if it complies with the Regional UFLS program and leaves the remaining interconnected bulk electric systems intact, in demand and generation balance, and with no unacceptable high voltages.

G6. In cases where area isolation with a large surplus of generation compared to demand can

be anticipated, automatic generator tripping or other remedial measures should be considered to prevent excessive high frequency and resultant uncontrolled generator tripping and equipment damage.

G7. UFLS relay settings and the underfrequency protection of generating units as well as any

other manual or automatic actions that can be expected to occur under conditions of frequency decline should be coordinated.

G8. The UFLS program should be separate, to the extent possible, from manual load shedding

schemes such that the same loads are not shed by both schemes.

G9. Generator underfrequency protection should not operate until the UFLS programs have operated and failed to maintain the system frequency at an operable level. This sequence of operation is necessary both to limit the amount of load shedding required and to help the systems avoid a complete collapse. Where this sequence is not possible, UFLS

Compliance Templates III.D. NERC Planning Standards Guides


programs should consider and compensate for any generator whose underfrequency protection is required to operate before a portion of the UFLS program.

G10. Plans to shed load automatically should be examined to determine if unacceptable

overfrequency, overvoltage, or transmission overloads might result. Potential unacceptable conditions should be mitigated.

If overfrequency is likely, the amount of load shed should be reduced or automatic

overfrequency load restoration should be provided.

If overvoltages are likely, the load shedding program should be modified (e.g., change the geographic distribution) or mitigation measures (e.g., coordinated tripping of shunt capacitors or insertion reactors) should be implemented to minimize that probability.

If transmission capabilities will likely be exceeded, the underfrequency relay settings

(e.g., location, trip frequency, or time delay) should be altered or other actions taken to maintain transmission loadings within capabilities.

G11. Where the UFLS program fails to arrest frequency decline, generators may be isolated

with local load to minimize loss of generation and enable timely system restoration.

Compliance Templates III. System Protection and Control NERC Planning Standards F. Special Protection Systems


Introduction A special protection system (SPS) or remedial action scheme (RAS) is designed to detect abnormal system conditions and take pre-planned, corrective action (other than the isolation of faulted elements) to provide acceptable system performance. SPS actions, include among others, changes in demand (e.g., load shedding), generation, or system configuration to maintain system stability, acceptable voltages, or acceptable facility loadings. The use of an SPS is an acceptable practice to meet the system performance requirements as defined under Categories A, B, or C of Table I of the I.A. Standards on Transmission Systems. Electric systems that rely on an SPS to meet the performance levels specified by the NERC Planning Standards must ensure that the SPS is highly reliable. Examples of SPS misoperation include, but are not limited to, the following:

1. The SPS does not operate as intended. 2. The SPS fails to operate when required. 3. The SPS operates when not required.

Compliance Templates III.F. NERC Planning Standards


Brief Description Establish and document Regional review procedures for special protection system (SPS) installations.

Category Documentation Section III. System Protection and Control F. Special Protection Systems Standards S1. An SPS shall be designed so that a single SPS component failure, when the SPS was

intended to operate, does not prevent the interconnected transmission system from meeting the performance requirements defined under Categories A, B, or C of Table 1 of the I.A Standards on Transmission Systems.

S2. The inadvertent operation of an SPS shall meet the same performance requirement

(Category A, B, or C of Table I of the I.A Standard on Transmission Systems) as that required of the contingency for which it was designed, and shall not exceed Category C.

S3. SPS installations shall be coordinated with other protection and control systems. S4. All SPS misoperations shall be analyzed for cause and corrective action. Measurement M1. Each Region whose members use or are planning to use an SPS shall have a documented

Regional review procedure to ensure the SPS complies with Regional criteria and NERC Planning Standards . The Regional review procedure shall include:

1) Description of the process for submitting a proposed SPS for Regional review. 2) Requirements to provide data that describes design, operation, and modeling of an SPS. 3) Requirements to demonstrate that the SPS design will meet above SPS Standards S1

and S2. 4) Requirements to demonstrate the proposed SPS will coordinate with other protection

and control systems and applicable Regional emergency procedures. 5) Regional definition of misoperation. 6) Requirements for analysis and documentation of corrective action plans for all SPS

misoperations. 7) Identification of the Regional group responsible for the Region’s review procedure and

the process for Regional approval of the procedure. 8) Determination, as appropriate, of maintenance and testing requirements.

Documentation of the Regional SPS review procedure shall be provided to affected Regions and NERC, on request (within 30 days).

Applicable to Regions.



Items to be measured Regional review procedure for assessing SPSs to ensure compliance with NERC Planning Standards and Regional criteria. Timeframe On request (within 30 days). Levels of Non-Compliance

Level 1 Documentation of the Regional procedure is missing one of the items listed in III.F. M1. Level 2 Documentation of the Regional procedure is missing two of the items listed in III.F. M1.

Level 3 Documentation of the Regional procedure is missing three of the items listed in III.F. M1.

Level 4 Documentation of the Regional procedure was not provided or is missing four or more of the items listed in III.F. M1.




Brief Description Establish Regional database for SPS installations. Category Data Section III. System Protection and Control

F. Special Protection Systems Standards S1. An SPS shall be designed so that a single SPS component failure, when the SPS was




S3. SPS installations shall be coordinated with other protection and control systems. Measurement M2. A Region that has a member with an SPS installed shall maintain an SPS database. The

database shall include the following types of information:

1) Design Objectives – Contingencies and system conditions for which the SPS was designed,

2) Operation – The actions taken by the SPS in response to disturbance conditions, and 3) Modeling – Information on detection logic or relay settings that control operation of the

SPS.

Documentation of the Regional database or the information therein shall be provided to affected Regions and NERC, on request (within 30 days).

Applicable to Regions. Items to be measured Regional database of SPS installations. Timeframe On request (within 30 days). Levels of Non-Compliance

Level 1 Regional database is missing one of the items listed in III.F. M2.



Level 2 Regional database is missing two of the items listed in III.F. M2. Level 3 Not applicable. Level 4 Regional database was not provided or is missing all of the elements listed in III.F. M2.




Brief Description Regional assessment of SPS coordination and effectiveness. Category Assessment Section III. System Protection and Control F. Special Protection Systems Standards S1. An SPS shall be designed so that a single SPS component failure, when the SPS was




S3. SPS installations shall be coordinated with other protection and control systems. Measurement M3. A Region shall assess the operation, coordination, and effectiveness of all SPSs installed in

the Region at least once every five years for compliance with NERC Planning Standards and Regional criteria. The Regions shall provide either a summary report or a detailed report of this assessment to affected Regions or NERC, on request (within 30 days). The documentation of the Regional SPS assessment shall include the following elements:

1) Identification of group conducting the assessment and the date the assessment was

performed. 2) Study years, system conditions, and contingencies analyzed in the technical studies on

which the assessment is based and when those technical studies were performed. 3) Identification of SPSs that were found not to comply with NERC Planning Standards

and Regional criteria. 4) Discussion of any coordination problems found between an SPS and other protection

and control systems. 5) Provide corrective action plans for non-compliant SPSs.

Applicable to Regions. Items to be Measured Result of Regional reviews for SPS compliance with NERC Planning Standards and Regional criteria. Timeframe On request (with 30 days).



Levels of Non-Compliance Level 1 The summary (or detailed) Regional SPS assessment is missing one of the items listed in III.F. M3. Level 2 The summary (or detailed) Regional SPS assessment is missing two of the items listed in III.F. M3.

Level 3 The summary (or detailed) Regional SPS assessment is missing three of the items listed in III.F. M3.

Level 4 The summary (or detailed) Regional SPS assessment is missing more than three of the items listed in III.F. M3 or was not provided.




Brief Description Data for review of SPS installations. Category Data Section III. System Protection and Control F. Special Protection Systems Standard S1. An SPS shall be designed so that a single SPS component failure, when the SPS was




S3. SPS installations shall be coordinated with other protection and control systems. Measurement M4. SPS owners shall maintain a list of and provide data for existing and proposed SPSs as

defined in Measurement III.F. S1-S3, M2. New or functionally modified SPSs shall be reviewed in accordance with the Regional procedures as defined in Measurement III.F. S1-S4, M1 prior to being placed in service. Documentation of SPS data and the results of studies that show compliance of new or functionally modified SPSs with NERC Planning Standards and Regional criteria shall be provided to affected Regions and NERC, on request (within 30 days).

Applicable to SPS owners. Items to be Measured SPS data and results of studies that show SPS compliance with NERC Planning Standards and Regional criteria. Timeframe On request (within 30 days). Levels of Non-Compliance

Level 1 SPS data was provided, but was incomplete according to the Regional SPS database requirements for III.F. M2.



Level 2 Results of studies that show compliance of new or functionally modified SPSs with the NERC Planning Standards and Regional criteria were provided, but were incomplete according to the Regional procedures for III.F. M1.

Level 3 Not applicable.

Level 4 No SPS data was provided in accordance with Regional SPS database requirements for III.F. M2, or the results of studies that show compliance of new or functionally modified SPSs with the NERC Planning Standards and Regional criteria were not provided in accordance with Regional procedures for III.F. M1.




Brief Description Notification and analysis of SPS misoperations and corrective action plans.

Category Documentation Section III. System Protection and Control F. Special Protection Systems Standard S4. All SPS misoperations shall be analyzed for cause and corrective action. Measurement M5. SPS owners shall analyze SPS operations and maintain a record of all misoperations in

accordance with Regional procedures in Measurement III.F. S1-S4, M1. Corrective actions shall be taken to avoid future misoperations.

Documentation of the misoperation analyses and the corrective action plans shall be

provided to the affected Regions and NERC, on request (within 90 days). Applicable to SPS owners. Items to be measured Documentation of SPS misoperations and corrective action plans. Timeframe On request (within 90 days of the incident or on request (within 30 days) if requested more than 90 days after the incident). Levels of Non-Compliance Level 1

Documentation of SPS misoperations is complete but documentation of corrective actions taken for all identified SPS misoperations is incomplete.

Level 2 Documentation of corrective actions taken for SPS misoperations is complete but documentation of SPS misoperations is incomplete.

Level 3 Documentation of SPS misoperations and corrective actions is incomplete.

Level 4 No documentation of SPS misoperations or corrective actions was provided.






Brief Description Documentation of SPS maintenance and testing programs. Category Documentation Section III. System Protection and Control F. Special Protection Systems Standards S5. SPS maintenance and testing programs shall be developed and implemented. Measurement M6. SPS owners shall have an SPS maintenance and testing program in place. This program

shall include SPS identification, summary of test procedures, frequency of testing, and frequency of maintenance. Documentation of the program and its implementation shall be provided to the appropriate Regions and NERC, on request (within 30 days).

Applicable to SPS owners. Items to be measured Documentation of the SPS maintenance and testing program. Timeframe On request (within 30 days). Levels of Non-Compliance

Level 1 Documentation of the maintenance and testing program was provided, but records indicate that implementation was not on schedule. Level 2 Documentation of the maintenance and testing program was incomplete, but records indicate implementation was on schedule.

Level 3 Documentation of the maintenance and testing program was incomplete, and records indicate implementation was not on schedule.

Level 4 No documentation of the maintenance and testing program or its implementation was provided.





Compliance Templates III.F. NERC Planning Standards Guides


III. System Protection and Control F. Special Protection Systems

G1. Complete redundancy should be considered in the design of an SPS with diagnostic and self-check features to detect and alarm when essential components fail or critical functions are not operational.

G2. No identifiable common mode events should result in the coincident failure of two or

more SPS components.

G3. An SPS should be designed to operate only for conditions that require specific protective or control actions.

G4. As system conditions change, an SPS should be disarmed to the extent that its use is

unnecessary.

G5. SPSs should be designed to minimize the likelihood of personnel error, such as incorrect operation and inadvertent disabling. Test devices or switches should be used to eliminate the necessity for removing or disconnecting wires during testing.

G6. The design of SPSs both in terms of circuitry and physical arrangement should facilitate

periodic testing and maintenance. Test facilities and test procedures should be designed such that they do not compromise the independence of redundant SPS groups.

G7. SPSs that rely on circuit breakers to accomplish corrective actions should as a minimum

use separate trip coils and separately fused dc control voltages.

Phone 609-452-8060 ¡ Fax 609-452-9550 ¡ www.nerc.com

NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731

Organization Standards Process Manual

NERC Board of Trustees

October 16, 2001

morganj

Exhibit E

2

Table of Contents

TABLE OF CONTENTS ............................................................................................................................................................ II

INTRODUCTION.........................................................................................................................................................................1 PURPOSE........................................................................................................................................................................................ 1 AUTHORITY.................................................................................................................................................................................. 1 BACKGROUND.............................................................................................................................................................................. 1

PRINCIPLES..................................................................................................................................................................................2 NEED FOR GUIDING PRINCIPLES................................................................................................................................................ 2 RELIABILITY PRINCIPLES............................................................................................................................................................ 2 MARKET INTERFACE PRINCIPLES.............................................................................................................................................. 2

ORGANIZATION STANDARD DEFINITION, CHARACTERISTICS, AND ELEMENTS ................................3 DEFINITION OF AN ORGANIZATION STANDARD...................................................................................................................... 3 CHARACTERISTICS OF AN ORGANIZATION STANDARD.......................................................................................................... 3 ELEMENTS OF AN ORGANIZATION STANDARD........................................................................................................................ 3 ORGANIZATION STANDARD TEMPLATE................................................................................................................................... 4

ROLES IN THE ORGANIZATION STANDARDS DEVELOPMENT PROCESS ..................................................6 NOMINATION, REVISION OR WITHDRAW OF A STANDARD................................................................................................... 6 PROCESS ROLES ........................................................................................................................................................................... 6

ORGANIZATION STANDARDS CONSENSUS DEVELOPMENT PROCESS .......................................................8 OVERVIEW.................................................................................................................................................................................... 8 STEP 1 – REQUEST TO DEVELOP A STANDARD OR REVISE AN EXISTING STANDARD....................................................... 9 STEP 2 – SOLICIT PUBLIC COMMENTS ON THE SAR............................................................................................................ 10 STEP 3 – AUTHORIZATION TO PROCEED WITH DRAFTING OF A NEW OR REVISED STANDARD..................................... 11 STEP 4 – DRAFT NEW OR REVISED STANDARD .................................................................................................................... 11 STEP 5 – SOLICIT PUBLIC COMMENTS ON DRAFT STANDARD............................................................................................ 12 STEP 6 – FIELD TESTING .......................................................................................................................................................... 12 STEP 7 – ANALYSIS OF THE COMMENTS AND FIELD TEST RESULTS................................................................................. 12 STEP 8 – BALLOT THE NEW OR REVISED STANDARD .......................................................................................................... 13 STEP 9 – ADOPTION OF THE ORGANIZATION STANDARD BY THE BOARD........................................................................ 14 STEP 10 – IMPLEMENTATION OF ORGANIZATION STANDARD ............................................................................................ 15 PROCESS DIAGRAM ................................................................................................................................................................... 16

SPECIAL PROCEDURES ........................................................................................................................................................17 URGENT ACTIONS...................................................................................................................................................................... 17 INTERPRETATIONS OF STANDARDS......................................................................................................................................... 17 REGIONAL DIFFERENCES.......................................................................................................................................................... 18 REGIONAL STANDARDS............................................................................................................................................................ 18 CRITERIA FOR REGIONAL STANDARDS AND REGIONAL DIFFERENCES............................................................................. 19 APPEALS...................................................................................................................................................................................... 19

MAINTENANCE OF ORGANIZATION STANDARDS AND PROCESS................................................................21 PARLIAMENTARY PROCEDURES.............................................................................................................................................. 21 PROCESS REVISIONS.................................................................................................................................................................. 21 STANDARDS PROCESS ACCREDITATION................................................................................................................................. 21 FIVE YEAR REVIEW................................................................................................................................................................... 21

Organization Standards Definition, Characteristics and Elements Process Manual

ii

FILING OF ORGANIZATION STANDARDS WITH REGULATORY AGENCIES.......................................................................... 21 ON-LINE STANDARDS INFORMATION SYSTEM...................................................................................................................... 21 ARCHIVED STANDARDS INFORMATION.................................................................................................................................. 22 NUMBERING SYSTEM................................................................................................................................................................ 22

SUPPORTING DOCUMENTS ...............................................................................................................................................23

APPENDIX A – INFORMATION IN A STANDARD AUTHORIZATION REQUEST.......................................24

Organization Standards Introduction Process Manual

Approved by the Board of Trustees October 16, 2001 1

Introduction

Purpose This manual defines the characteristics of an Organization Standard of the North American Electric Reliability Council (NERC) and establishes the process for development of consensus for approval, revision, reaffirmation, and withdrawal of such standards. NERC Organization Standards apply to the reliability planning and operation of bulk electric systems of North America. Authority This manual is published by the authority of the NERC Board of Trustees, who shall have the sole authority to modify the manual. The manual may, at the discretion of the Board of Trustees, be filed with regulatory agencies, consistent with the NERC Articles of Incorporation and Bylaws. A procedure for revising the manual is provided in the section titled Maintenance of Organization Standards and Process. Background NERC is a not- for-profit company formed as a result of the Northeast blackout in 1965 to promote the reliability of the bulk electric systems of North America. NERC comprises ten Regional Reliability Councils that account for virtually all the electricity supplied in the United States, Canada, and a portion of Baja California Norte, Mexico. NERC works with all segments of the electric industry, including electricity users, to develop standards for the reliable planning and operation of bulk electric systems. Historically, NERC standards were effectively applied on a voluntary basis. The NERC Board of Trustees has established that enforcement of these standards through penalties and sanctions is a necessary step for the continuing reliability of North American bulk electric systems. While NERC Organization Standards are intended to promote reliability, they must at the same time accommodate competitive electricity markets. Reliability is a necessity for electricity markets and robust electricity markets can support reliability. This manual has been developed for implementation while NERC is in a transition state to become the North American Electric Reliability Organization (NAERO). Once reliability legislation is enacted, and as NAERO is formed, this manual may be revised as necessary to incorporate any additional regulatory requirements associated with the development, approval, and implementation of Organization Standards.

Organization Standards Principles Process Manual


Principles

Need for Guiding Principles The NERC Board of Trustees has adopted Reliability Principles and Market Interface Principles to define the purpose, scope, and nature of Organization Standards. As these Principles are fundamental to reliability and the market interface, these Principles provide a constant beacon to guide the development of Organization Standards. The Board of Trustees may modify these Principles from time to time, as necessary to adapt its vision for Organization Standards. Persons and committees that are responsible for the Organization Standards process shall consider these Principles in the execution of those duties. Reliability Principles NERC Organization Standards are based on certain Reliability Principles that define the foundation of reliability for North American bulk electric systems. Each Organization Standard shall enable or support one or more of the Reliability Principles, thereby ensuring that each standard serves a purpose in support of reliability of the North American bulk electric systems. Each Organization Standard shall also be consistent with all of the Reliability Principles, thereby ensuring that no standard undermines reliability through an unintended consequence. Market Interface Principles Recognizing that bulk electric system reliability and electricity markets are inseparable and mutually interdependent, all Organization Standards shall be consistent with the Market Interface Principles. Consideration of the Market Interface Principles is intended to assure Organization Standards are written such that they achieve their reliability objective without causing undue restrictions or adverse impacts on competitive electricity markets.



Organization Standard Definition, Characteristics, and Elements

Definition of an Organization Standard An Organization Standard defines certain obligations or requirements of entities that operate, plan, and use the bulk electric systems of North America. The obligations or requirements must be material to reliability and measurable. Each obligation and requirement shall support one or more of the stated Reliability Principles and shall be consistent with all of the stated Reliability and Market Interface Principles. Characteristics of an Organization Standard Organization Standards may include standards for the operation and planning of interconnected systems and market interface practices, consistent with the Reliability and Market Interface Principles. The format and process defined by this manual applies to all Organization Standards. An Organization Standard shall have the following characteristics:

• Material to Reliability – An Organization Standard shall be material to the reliability of bulk electric systems of North America. If the reliability of the bulk electric system could be compromised without a particular standard or by a failure to comply with that standard, then the standard is material to reliability.

• Measurable − An Organization Standard shall establish technical or performance requirements that can be practically measured.

Although Organization Standards have a common format and process, several types of Organization Standards may exist, each with a different approach to measurement:

• Technical standards related to the provision, maintenance, operation, or state of electric systems will likely contain measures of physical parameters and will often be technical in nature.

• Performance standards related to the actions of entities providing for or impacting the reliability of bulk electric systems will likely contain measures of the results of such actions, or the nature of the performance of such actions.

• Preparedness standards related to the actions of entities to be prepared for conditions that are unlikely to occur but are critical to reliability will likely contain measures of such preparations or the state of preparedness, but measurement of actual outcomes may occur infrequently or never.

Elements of an Organization Standard An Organization Standard shall consist of the elements shown in the Organization Standard Template. These elements are intended to apply a systematic discipline in the development and revision of Organization Standards. This discipline is necessary to achieving standards that are



measurable, enforceable, and consistent. The format allows a clear statement of the purpose, requirements, measures, and penalties for non-compliance associated with each standard. All mandatory requirements of an Organization Standard shall be within an element of the standard. Supporting documents to aid in the implementation of a standard may be referenced by the standard but are not part of the standard itself. Types of supporting documents are described in a later section of the manual. Organization Standard Template

Core Elements of an Organization Standard Identification Number

A unique identification number assigned in accordance with a published classification system to facilitate tracking and reference to the standards.

Title A brief, descriptive phrase identifying the topic of the standard. Effective Date and Status

The effective date of the standard or, prior to adoption of the standard by the Board of Trustees, the proposed effective date. The status of the standard will be indicated as active or by reference to one of the numbered steps in the standards process.

Purpose The purpose of the standard. The purpose shall explicitly state what outcome will be achieved by the adoption of the standard. The purpose is agreed to early in the process as a step toward obtaining approval to proceed with the development of the standard. The purpose should link the standard to the relevant Principle(s).

Requirement(s) Explicitly stated technical, performance, and preparedness requirements. Each requirement identifies who is responsible and what action is to be performed or what outcome is to be achieved. Each statement in the requirements section shall be a statement for which compliance is mandatory. Any additional comments or statements for which compliance is not mandatory, such as background or explanatory information, should be placed in a separate document and referenced (see Supporting References).

Measure(s) Each requirement shall be addressed by one or more measurements. Measurements that will be used to assess performance and outcomes for the purpose of determining compliance with the requirements stated above. Each measurement will identify to whom the measurement applies. Each measurement shall be tangible, practical, and as objective as is practical. It is important to realize that the measurements are proxies to assess required performance or outcomes. Achieving the full compliance level of each measurement should be a necessary and sufficient indicator that the requirement was met.

Expected Performance or Outcomes

Defines the expected level of performance or outcomes for each measurement.



Compliance Administration Elements Compliance Monitoring Process

Defines for each measure: • The specific data or information that is required to measure

performance or outcomes. • The entity that is responsible to provide the data or information for

measuring performance or outcomes. • The process that will be used to evaluate data or information for the

purpose of assessing performance or outcomes. • The entity that is responsible for evaluating data or information to

assess performance or outcomes. • The time period in which performance or outcomes is measured,

evaluated, and then reset. • Measurement data retention requirements and assignment of

responsibility for data archiving. Levels of Non-Compliance

Defines the levels of non-compliance for each measure, typically based on the actual or potential severity of the consequences of non-compliance.

Sanctions Defines all penalties or sanctions associated with non-compliance, typically based on level of non-compliance and number of offenses.

Supporting Information Elements

Interpretations Formal interpretations of the Organization Standard. Interpretations are

temporary, as the standard should be revised to incorporate the interpretation.

Supporting References

This section will reference related documents that support implementation of the Organization Standard, but are not themselves mandatory. Examples include, but are not limited to: • Glossary of Terms1 • Developmental history of the standard and prior versions • Subcommittee(s) responsible for standard • Notes pertaining to implementation or compliance • Standard Reference • Standard Supplement • Procedure • Practices • Training Reference • Technical Reference • White Paper • Internet links to related information

1 Although a Glossary of Terms is listed as a reference item here, the Glossary of Terms associated with Organization Standards may itself become a standard, subject to the approval process defined by this manual.

Organization Standards Roles Process Manual


Roles in the Organization Standards Development Process

Nomination, Revision or Withdraw of a Standard Any member of NERC, including any member of a Regional Reliability Council, or group within NERC shall be allowed to request that an Organization Standard be developed, modified, or withdrawn. Additionally, any person (organization, company, government agency, individual, etc.) who is directly and materially affected by the reliability of North American bulk electric systems shall be allowed to request an Organization Standard be developed, modified, or withdrawn. Process Roles Board of Trustees – The NERC Board of Trustees shall consider for adoption as Organization Standards the standards that have been approved by the Standards Committee. Once the Board adopts an Organization Standard, compliance with the standard will be enforced consistent with the effective date. Stakeholder Committee – The NERC Stakeholder Committee shall advise the Board of Trustees on Organization Standards presented for adoption by the Board. Standards Committee – The Standards Committee is comprised of the voting members of the three NERC Standing Committees, as defined by the “Organization and Procedures Manual for the NERC Standing Committees.” The Standards Committee shall constitute a single pool of voting members for the purpose of considering the approval of Organization Standards. The Standards Committee is responsible for assessing the need for and technical merits of proposed standards, and for assuring comments received in the process are provided due consideration. The Standards Committee shall meet in an open forum at regularly scheduled intervals to consider all proposed new standards, revisions to standards, or withdrawal of standards. The Standards Committee shall electronically conduct a ballot of its members for each standard, revision or request to withdraw standards submitted for approval. Standards Authorization Committee – The Standards Authorization Committee shall consist of the members of the Executive Committees of the three standing committees. The Standards Authorization Committee shall meet at regularly scheduled intervals (either in person, or by other means) to consider which requests for new or revised standards should be assigned for development. The Standards Authorization Committee will coordinate the assignment of appropriate subcommittees and other NERC working groups who will work with the standards process staff to draft the new or modified standard. Standards Process Manager – The Organization Standards process shall be administered by a Standards Process Manager. The Standards Process Manager is responsible for assuring that the development and revision of standards is in accordance with this manual. The Standards Process Manager works to assure the integrity of the process and consistency of quality and completeness of the Organization Standards. The Standards Process Manager facilitates all steps in the process.

Organization Standards Roles Process Manual


Standards Process Staff – NERC Staff will be assigned to assist subcommittees, working groups, and task forces in the drafting of Organization Standards that have been assigned for development. NERC staff that assisting in the drafting of standards will work under the direction of the Standards Process Manager. The NERC Staff, subcommittees, and work groups assigned a specific standard will seek inputs and feedback from other subcommittees, working groups, or task forces. The staff may assemble additional necessary subject matter experts if an existing group does not contain the requisite expertise. Subcommittees, Working Groups, and Task Forces – The subcommittees, working groups, and task forces within NERC serve an active role in the standards process. Each subcommittee, working group, or task force may submit requests for standards and is expected to be a primary source of requests for standards. They will often assist in the standards process by assuming the responsibilities of a requester to add or change a standard. They will provide technical inputs for the development and revision of standards. They will work with the assigned staff to draft the proposed standards or revisions to standards. They will review and prepare responses to public comments. As the requester of a proposed standard or proposed revision to a standard, these groups have key decisions in the standards development process. Each subcommittee, working group, and task force shall perform these activities within its assigned scope and subject to the authority granted by its sponsoring standing committee. Work assignments for these groups shall be established early in the process, prior to authorizing the development of the standard. NERC and Regional Reliability Council Members – The members of NERC and the Regional Reliability Councils may request standards and may comment on proposed standards. Members may also affect the standards process through representative members of the Standards Committee and other stakeholder groups within NERC. Requester – A Requester is any person (organization, company, government agency, individual, etc.) that submits a complete request for development, revision or withdraw of a standard. The Requester will often be a subcommittee, working group, or task force of NERC, although any person that is directly and materially affected by an existing standard or the need for a new standard may submit a request for a new standard or revision to a standard. Compliance Enforcement Program – The mission of the NERC Compliance Enforcement Program is to manage and enforce compliance with NERC Organization Standards. The development of an Organization Standard, in particular the measures and compliance administration portions of the standard, shall have direct input from the Compliance Enforcement Program. Field testing will also be managed and coordinated with the Compliance Program. The Compliance Program Director and appropriate working groups shall provide inputs and comments during the standards development process to ensure the measures will be effective and other aspects of the Compliance Enforcement Program can be practically implemented.

Organization Standards Consensus Development Process Process Manual


Organization Standards Consensus Development Process

Overview The process for developing and approving Organization Standards is generally based on the procedures of the American National Standards Institute (ANSI) and other standards setting organizations in the United States and Canada. The NERC process has the following characteristics:

• Due process – Any person with a direct and material interest has a right to participate by: a) expressing an opinion and its basis, b) having that position considered, and c) appealing if adversely affected.

• Openness – Participation is open to all persons who are directly and materially affected by North American bulk electric system reliability. There shall be no undue financial barriers to participation. Participation shall not be conditional upon membership in NERC or any organization, and shall not be unreasonably restricted on the basis of technical qualifications or other such requirements.

• Balance – The NERC standards development process shall have a balance of interests and shall not be dominated by any single interest category.

The NERC process is intended to develop consensus, first on the need for the standard, then on the standard itself. The process includes the following key elements:

• Nomination of a proposed standard, revision to a standard, or withdrawal of a standard using a Standard Authorization Request (SAR).

• Public posting of the SAR to allow all parties to review and provide comments on the need for the proposed standard and the expected outcomes and impacts from implementing the proposed standard. Notice of standards shall provide an opportunity for participation by all directly and materially affected persons.

• Review of the public comments in response to the SAR and prioritization of proposed standards, leading to the authorization to deve lop standards for which there is a consensus-based need.

• Assignment of appropriate NERC subcommittees and working groups to draft the the new or revised standard.

• Drafting of the standard.

• Public posting of the draft standard to allow all parties to review and provide comments on the draft standard. At this point the need for the standard has been established and comments should focus on aspects of the draft standard itself.

• Field testing of the draft standard and measures. The need and extent of field testing shall be determined in the authorization process considering the recommendation of the NERC Compliance Director. Field testing may be industry-wide or may consist of one or more lesser scale demonstrations. Field testing should be cost effective and practical, yet sufficient to validate the requirements, measures, measurement processes, and other elements of the



standard necessary to implement the Compliance Program. For some standards and their associated measures, field testing may not be appropriate, such as those measures that consist of administrative reports.

• Formal balloting of the standard for approval by the Standards Committee, representing all stakeholder sectors of the industry.

• Re-ballot to consider specific comments by those submitting comments with negative votes.

• Adoption by the Board of Trustees.

• An appeals mechanism as appropriate for the impartial handling of substantive and procedural complaints regarding action or inaction related to the standards process.

Step 1 – Request to Develop a Standard or Revise an Existing Standard The first three steps in the process serve to establish consensus on the need for the standard. Requests to develop, revise, or withdraw2 an Organization Standard shall be submitted to the Standards Process Manager by completing a Standard Authorization Request (SAR). The SAR is a description of the new or revised standard along with a proposed implementation plan. The SAR provides sufficiently descriptive detail to clearly define the scope of the standard. The SAR also states the purpose of the standard. A needs statement will provide the justification for the development or revision of the standard, including an assessment of the reliability and market interface impacts of implementing or not implement ing the standard. Appendix A provides a sample of the information in a SAR. The Standards Process Manager shall maintain this form and make it available electronically. Any member of NERC, any member of any Regional Reliability Council, and any committee or subgroup within the NERC organization may initiate a SAR. Additionally, any person that is directly and materially affected by an existing standard or the need for a new standard shall be allowed to submit a SAR. The Requester will submit the SAR to the Standards Process Manager electronically and the Standards Process Manager will electronically acknowledge receipt of the SAR. The Standards Process Manager will assist the submitting party in developing the SAR and verify that the SAR is in compliance with this manual. The Standards Process Manager shall forward all properly completed SARs to the Standards Authorization Committee. The Standards Authorization Committee shall meet at established intervals to review all pending SARs. The frequency of this review process will depend on workload, but in no case shall a properly completed SAR wait for Standards Authorization Committee action more than 60 days from the date of receipt. The Standards Authorization

2 Actions in the remaining steps of the standards process apply to proposed new standards, revisions to existing standards, or withdrawal of existing standards, unless explicitly stated otherwise.



Committee, guided by the Reliability and Market Interface Principles, may take one of the following actions:

• Remand the SAR back to the Standards Process Manager for additional work. In this case, the Standards Process Manager may request additional information for the SAR from the Requester.

• Accept the SAR as a candidate for a new or revised standard. If the Standards Authorization Committee accepts a SAR as a candidate for a new or revised standard, it will assign an appropriate subcommittee or group within NERC to provide technical support and analysis of comments for that SAR.

• Reject the SAR. If the Standards Authorization Committee rejects a SAR, it will provide a written explanation for rejection to the Requester within 30 days of the rejection decision.

If the Standards Authorization Committee rejects a SAR, the Requester may submit in writing to any of the three standing committees of NERC a request for review of the SAR. The requested standing committee shall review the request and will either confirm the rejection of the SAR or accept the SAR and direct the Standards Authorization Committee to reassign the SAR to a status of accepted as a candidate for development. Once the SAR has been accepted as a candidate for development, the Standards Authorization Committee will assign one or more subcommittees, working groups, or task forces to assist the Requester and the Standards Process Manager in remaining steps of the process. The assigned group(s) may be the Requester, in the case that a NERC group has submitted the SAR. The Standards Authorization Committee will designate one group as the primary group if more than one subcommittee, working group or task force is assigned. The status of SARs shall be tracked electronically. The SAR and its status shall be posted for public viewing including any actions or decisions. Step 2 – Solicit Public Comments on the SAR Once a SAR has been accepted by the Standards Authorization Committee as a candidate for the development of a new or revised standard, the SAR will be posted at the next regular posting interval for the purpose of soliciting public comments. SARs will be posted and publicly noticed at regularly scheduled intervals. Establishment of a regular time for posting of SARs will allow interested parties to know when to expect the next set of SARs. Comments on the SARs will be accepted for a 30-day period from the notice of posting. Comments will be accepted on- line using an Internet-based application. The Standards Process Manager will provide a copy of the comments to the Requester and assigned subcommittees, working groups, or task forces. Based on the comments, the Requester may decide to submit the SAR for authorization, to withdraw the SAR, or to revise and resubmit it to the Standards Process Manager for another posting in the next available comment period. The assigned group shall assist in the review of comments, the decision to continue or not, and any necessary revisions for another posting.



The Requester, assisted by the assigned group, shall give prompt consideration to the written views and objections of all participants. An effort to resolve all expressed objections shall be made and each objector shall be advised of the disposition of the objection and the reasons therefor. In addition, each objector shall be informed that an appeals process exists within the NERC standards process. While there is no established limit on the number of times a SAR may be posted for comment, the Standards Authorization Committee retains the right to reverse its prior decision and reject a SAR if it believes continued revisions are not productive. Once again, the Standards Authorization Committee shall notify the Requester in writing of the rejection and the Requester may appeal the rejection to a standing committee. During the SAR comment process, the Requester may become aware of potential regional differences related to the proposed standard. To the extent possible any regional differences or exceptions should be made a part of the SAR so that, if the SAR is authorized, such variations will be made a part of the draft new or revised standard. Step 3 – Authorization to Proceed with Drafting of a New or Revised Standard After the public comments on the SAR, the Requester may decide to submit the SAR to the Standards Authorization Committee for authorization to draft the standard. The Standards Authorization Committee reviews the comments received in response to the SAR and any revisions to the SAR. The Standards Authorization Committee, once again considering the Reliability and Market Interface Principles and considering the public comments received and their resolution, may then take one of the following actions:

• Authorize the drafting of the proposed standard or revisions to a standard.

• Reject the SAR with a written explanation to the Requester and post that explanation. If the Standards Authorization Committee rejects a SAR, the Requester may submit in writing to any of three standing committees an appeal to reverse that decision. The requested standing committee will review the appeal, including public comments received, and will either confirm the rejection of the SAR or accept the SAR and direct the Standards Authorization Committee to reassign the SAR to a status of accepted for development. Step 4 – Draft New or Revised Standard Once a SAR has been authorized by the Standards Authorization Committee to proceed to the drafting stage, the Standards Authorization Committee shall assign the development of the standard to resources with the necessary technical expertise, such as subcommittees, working groups, or task forces. The Standards Process Manager shall assign staff personnel to assist in the drafting of the standard. The drafting of measures and compliance administration aspects of the standard will be coordinated with the Compliance Program.



Once the standard has been drafted, the Standards Process Manager will review the standard for consistency of quality and completeness. The Standards Process Manager will also ensure the draft standard is within the scope and purpose identified in the SAR. This review should occur within a 30 day period. Once the Standards Process Manager has completed this review, the new or revised standard is posted for public comment. Step 5 – Solicit Public Comments on Draft Standard Once a draft standard has been verified by the Standards Process Manager to be within the scope and purpose of the SAR and in compliance with this manual, the Standards Process Manager will post the draft standard in the next regular posting interval for the purpose of soliciting public comments. The posting of the draft standard will be linked to the SAR for reference. Comments on the draft standard will be accepted for a 30-day period from the notice of posting. Comments will be accepted on- line using a web-based application along with other electronic means as necessary. Since the need for the standard was established by authorization of the SAR, comments at this stage should identify specific issues with the draft standard and propose alternative language. The comments may include recommendations to accept or reject the standards and reasons for that recommendation. Step 6 – Field Testing The NERC Compliance Director will determine if field testing of the proposed new or revised standard is needed and submit his recommendation to the Standards Authorization Committee for approval. Once approved, the Standards Process Manager will facilitate field testing of the standard to validate the standard, the measurement process, and any other elements of the standard necessary to the administration of the Compliance Program. In some cases, measurement may be an administrative task and no field testing is required at all. In other cases, one or more limited scale demonstrations may be sufficient. Comments may be solicited during the field test period. Step 7 – Analysis of the Comments and Field Test Results The Standards Process Manager will assemble the comments on the draft standard and distribute those comments to the groups assigned to support the development of the standard and the Requester. The assigned group, assisted by the Requester, shall give prompt consideration to the written views and objections of all participants. An effort to resolve all expressed objections shall be made and each objector shall be advised of the disposition of the objection and the reasons therefor in addition to public posting of the responses. In addition, each objector shall be informed that an appeals process exists within the NERC standards process. The assigned NERC group shall choose one of the following decisions:

• Submit the draft standard for balloting as it stands, along with the comments received and responses to the comments. Based on the comments received and field testing, the assigned group may include revisions that are not substantive. A substantive change is one that



directly and materially affects the use of the standard, including, for example: changing “shall” to “should”, changing “should” to “shall”; adding, deleting, or revising requirements; or adding, deleting, or revising measures for which compliance is mandatory.

• Withdraw the request for a standard.

• Make substantive revisions to the draft standard by returning to Step 4. Step 8 – Ballot the New or Revised Standard If a decision is made to submit the draft standard to a vote, the draft standard, all comments received, and the responses to those comments shall be posted electronically to the Standards Committee. A proposed standard shall be presented to the Standards Committee at some time prior to the conduct of the ballot for discussion in an open forum. This discussion may occur any time during Steps 4−8 prior to the conduct of the ballot but should be done as close to balloting time as possible. The ballot will be conducted electronically. All members of the Standards Committee shall be eligible to vote on all standards. The time window for voting will be designated when the draft standard is posted to the Standards Committee. In no case will the voting time window start sooner than 30 days from the notice of the posting to the Standards Committee. Typically, the voting time window will be a period of 10 days. Approval of an Organization Standard or revision to an Organization Standard requires both: • A quorum, which is established by at least 50% of the members of the Standards Committee

submitting a response with an affirmative vote, a negative vote, or an abstention; and • A two-thirds majority of votes cast are affirmative. The number of votes cast is the sum of

affirmative and negative votes, excluding abstentions and non-responses. For example, assuming there are 99 voting members of the Standards Committee (33 from each Standing Committee), then there must be a minimum of 50 ballot responses to establish a quorum. A response of “Abstain” counts as a response for the purpose of establishing a quorum. If there are 70 ballots submitted with 40 affirmative votes, 20 negative votes, and 10 abstentions, then a two-thirds majority is established as 40 affirmative votes out of a total of 60 affirmative and negative votes cast. Each member of the Standards Committee may vote on one of the following positions:

• Affirmative

• Affirmative, with comment

• Negative, with reasons (the reasons for a negative vote may be given and if possible should include specific wording or actions that would resolve the objection)

• Abstain



Members of the Standards Committee should submit any comments on the proposed standard during the public comment period and should not raise new issues during the balloting process except as presented by themselves or another commenter during the public comment period. The Standards Process Manager shall facilitate the assigned groups, assisted by the Requester, in preparing a response to negative votes submitted with reasons. The member submitting the negative vote with reasons will determine if the response provided satisfies those reasons. No response is required to the other three types of ballot responses. A negative vote that does not contain a statement of reason does not require a response. If there are no negative votes reasons from the first ballot, then the results of the first ballot shall stand. If, however, one or more members submit negative votes with reasons, regardless whether those reasons are resolved or not, a second ballot shall be conducted. In the second ballot, members of the Standards Committee shall again be presented the proposed standard (unchanged from the first ballot) along with the reasons for negative votes, the responses, and any resolution of the differences. All members shall be permitted to reconsider and change their vote from the first ballot. Members that did not respond to the first ballot shall be permitted to vote in the second ballot. In the second ballot, votes will be counted by exception only members on the second ballot may indicate a revision to their original vote, otherwise their vote shall remain the same as in the first ballot. If a second ballot is conducted, the results of the second ballot shall determine the status of the standard, regardless the outcome of the first ballot. The voting time window for the second ballot is once again ten days. The 30-day posting is not required for the second ballot. Members may submit comments in the second ballot but no response is required. In the second ballot step, no revisions to the standard are permitted, as such revisions would not have been subject to public comment. However, if the Standards Authorization Committee determines that revisions proposed during the ballot process would likely provide an opportunity to achieve consensus on the standard, then such revisions may be made and the draft standard posted for public comment again beginning with Step 5 and continuing with subsequent steps. The Standards Process Manager shall post the final outcome of the ballot process. If the standard is rejected, the process is ended and any further work in this area would require a new SAR. If the standard is approved, the consensus standard will be posted and presented to the Board of Trustees for adoption by NERC. Step 9 – Adoption of the Organization Standard by the Board An Organization Standard submitted for adoption by the Board of Trustees must be publicly posted and noticed at least 30 days prior to action by the Board of Trustees. At a regular or special meeting, the Board of Trustees shall consider adoption of the proposed Organization Standard. The Board will consider the results of the balloting and dissenting opinions. The Board will consider any advice offered by the NERC Stakeholder Committee. The Board may



adopt or reject a standard, but may not modify a proposed Organization Standard. If the Board chooses not to adopt a standard, it should provide its reasons for not doing so. An Organization Standard that is adopted by the Board shall become effective on a date designated by the Board in accordance with the implementation plan. The standard will be publicly posted, showing the final status. Step 10 – Implementation of Organization Standard Once an Organization Standard is adopted, all persons and organizations subject to the Bylaws of NERC are required to comply with the standard in accordance with those Bylaws and other applicable agreements. The adopted Organization Standard will then be monitored by the NERC Compliance Enforcement Program to oversee the implementation and assess the effectiveness of the Organization Standard. The Board of Trustees has established a separate Compliance Program to measure compliance with the standards and administer sanctions as appropriate. After adoption of a NERC Organization Standard, the standard will be forwarded to the Compliance Program for implementation. Organization Standards will be filed with applicable regulatory agencies in the United States, Canada, and Mexico as required to implement the NERC Compliance Enforcement Program.



Process Diagram

Individual or Group IdentifiesPotential Need for a New or

Revised Standard

Individual or Group completesStandard Authorization Request

Standard AuthorizationRequest Reviewed byStandard AuthorizationCommittee - Ready to

post for publiccomment?

StandardAuthorization

Request Submitted

No

Public Comments Assembledand Presented to Originatorand Standard Authorization

Committee

Standard AuthorizationRequest Posted and

Noticed for PublicComment Period

Yes

Standard AuthorizationCommittee - ReviewPublic Comments -

Ready to draft Standard?

No

YesStandards ProcessManager assigns to

NERC Staff for Draftingand Identifies Technical

Support Persons

SARassigned toassignedgroup fordrafting

Is Draft Standardwithin the Scopeand Purpose asDescribed by the

SAR?

Yes

Proposed StandardPosted and Noticed forPublic Comment Period

Public Comments andResponses Assembled

Posted and Presented toStandards Committee

ProposedStandardBalloted

Electronically

Did 50% of theStandards

Committee Vote?

No

Yes

Any No Votes withReasons?

Yes

No ProposedRevisionsBalloted

ElectronicallyDid the proposed

Standard obtain thenecessary affirmative

votes?Did the proposed

Standard obtain thenecessary affirmative

votes?

Standard Fails

No

Standard Approved forBoard of Trustees

Consideration

Yes

Yes

StandardPresented to Board

Of Trustees

Board ofTrustees votes

for Adoption

Implementation

Standard NotAdopted

Yes

No

Process for the Development of NERC/NAERO Standards

Standard ProcessManager assemble

reasons andpresent toStandardsCommittee

Ste

p 1

Ste

p 2

Ste

p 3

Ste

p 4

Ste

p 5

Limited FieldTesting Required Field Evaluation

No

Review andRespond to Comments

and Field Evaluation

Ballot

Yes

Withdraw

Standard Fails

Redraft

Ste

p 6

Ste

p 7

Ste

p 8

Ste

p 9

Step 10Note: Appeals may be submitted to the NERC Standards ProcessManager at any point in the process

No

Organization Standards Special Procedures Process Manual


Special Procedures Urgent Actions Under certain conditions, the Standards Authorization Committee may designate a proposed standard or revision to a standard as requiring urgent action. Urgent action may be appropriate when a delay in implementing a proposed standard or revision can materially impact reliability of the bulk electric systems. The Standards Authorization Committee must use its judgment carefully to ensure an urgent action is truly necessary and not simply an expedient way to change or implement a standard. A Requester prepares a SAR and a draft of the proposed standard and submits it to the Standards Process Manager. The SAR must include a justification for urgent action. The Standards Process Manager submits the request to the Standards Authorization Committee for its consideration. If the Standards Authorization Committee designates the requested standard or revision as an urgent action item, then the draft is posted for balloting by the Standards Committee as in Step 8. This posting requires a minimum 30-day posting period before the ballot and applies the same voting procedure as described in Step 7. If the standard is approved by the requisite two-thirds majority, then the standard is approved for immediate implementation. Any standard approved as an urgent action shall have a termination date specified that shall not exceed one year from the approval date. Should there be a need to make the standard permanent, then the standard would be required to go through the full consensus process. Urgent actions that expire may be renewed no more than once using the urgent action process again, in the event a permanent standard is not adopted. Interpretations of Standards All persons who are directly and materially affected by the reliability of North American bulk electric systems shall be permitted to request an interpretation of the standard. The person requesting an interpretation will send a request to the Standards Process Manager explaining the specific circumstances surrounding the request and what clarifications are required as applied to those circumstances. The request should indicate the material impact to the requesting party or others caused by the lack of clarity or a possibly incorrect interpretation of the standard. The Standards Process Manager will forward the request to the subcommittee, working group, or task force with the relevant expertise to address the clarification. As soon as practical (not more than 45 days), the assigned subcommittee or work group will draft a written clarification to the standard addressing the issues raised. The draft interpretation will be balloted by the members of the Standards Committees in accordance with the process in Step 8. If approved, the interpretation is appended to the standard and is effective immediately. The interpretation will stand until such time as the standard is revised through the normal process, at which time the standard will be modified to incorporate the clarifications provided by the interpretation.



Regional Differences A Regional Difference is an aspect of a NERC Organization Standard that applies only within a given Region or Regions. A Regional Difference may be used, for example, to exempt a particular Region from all or a portion of a NERC Organization Standard that does not apply in that Region. A Regional Difference may establish different measures or performance criteria as necessary to achieve reliability within that Region. To the maximum extent feasible, Regional Differences should be addressed through the NERC standards process and incorporated into and approved as part of the NERC Organization Standard. In all cases, if a requirement would otherwise be inconsistent with or less stringent than a NERC Organization Standard, then that Regional Difference shall be made part of the NERC Organization Standard. Regional Differences should be identified and considered when the SAR is posted for comment. Regional Differences should also be considered in the drafting of a standard, with the intent to make any necessary Regional Differences a part of the standard. Public comments on the draft standard provide a second opportunity to ensure necessary Regional Differences have been accommodated in the draft. The public posting also allows for all impacted parties to identify the requirements of a NERC Organization Standard as applied within all regions and interconnections. Regional Differences that are proposed to be made part of a NERC Organization Standard shall be considered during the NERC standards process in accordance with the Criteria for Regional Standards and Regional Differences section below. These criteria provide that: • Interconnection-wide Regional Differences are presumed to be valid and there is a burden of

proof to demonstrate otherwise in accordance with the stated criteria; and • Regional Differences that are not applied on an Interconnection-wide basis are not presumed

to be valid but may be demonstrated by the proponent to be valid in accordance with the stated criteria.

Regional Standards Regions may develop, through their own processes, separate Regional Standards that go beyond, add detail to, or implement NERC Organization Standards, or tha t cover matters not addressed in NERC Organization Standards. Regional Standards may be developed and exist separately from NERC Organization Standards, or may be proposed as NERC Organization Standards. Regional Standards that exist separately from NERC Organization Standards shall not be inconsistent with or less stringent than NERC Organization Standards. A Regional Standard that is proposed to be made a NERC Organization Standard shall be considered during the NERC standards process in accordance with the Criteria for Regional Standards and Regional Differences section below. These criteria provide that: • Interconnection-wide Regional Standards are presumed to be valid and there is a burden of

proof to demonstrate otherwise in accordance with the stated criteria; and



• Regional Standards that are not applied on an Interconnection-wide basis are not presumed to be valid but may be demonstrated by the proponent to be valid in accordance with the stated criteria.

Criteria for Regional Standards and Regional Differences Proposals for Regional Standards or Regional Differences that are intended to apply on an Interconnection-wide basis shall be presumed to be valid and included in a NERC Organization Standard unless there is a clear demonstration within the NERC standards process that the proposed Regional Standard or Regional Difference: • was not developed in a fair and open process that provided an opportunity for all interested

parties to participate; • would have a significant adverse impact on reliability or commerce in other Interconnections; • fails to provide a level of reliability of the bulk electric system within the Interconnection

such that the Regional standard would be likely to cause a serious and substantial threat to public health, safety, welfare, or national security; or

• would create a serious and substantial burden on competitive markets within the Interconnection that is not necessary for reliability.

Proposals for Regional Standards or Regional Differences that are intended to apply only to part of an Interconnection will be included in a NERC Organization Standard only if the proponent demonstrates that the proposed Regional Standard or Regional Difference: • was developed in a fair and open process that provided an opportunity for all interested

parties to participate; • would not have an adverse impact on commerce that is not necessary for reliability; • provides a level of bulk electric system reliability that is adequate to protect public health,

safety, welfare, and national security and would not have a significant adverse impact on reliability; and

• is based on a justifiable difference between Regions or between subregions within the Regional Council’s geographic area.

Appeals Persons who have directly and materially affected interests and who have been or will be adversely affected by any substantive or procedural action or inaction related to the development, approval, revision, reaffirmation, or withdrawal of an Organization Standard shall have the right to appeal. This appeals process applies only to the NERC Organization Standards process as defined in this manual. The burden of proof to show adverse effect shall be on the appellant. Appeals shall be made within 30 days of the date of the action purported to cause the adverse effect, except appeals for inaction which may be made at any time. In all cases, the request for appeal must be made prior to the next step in the process. The final decisions of any appeal shall be documented in writing and made public.



The appeals process provides two levels, with the goal of expeditiously resolving the issue to the satisfaction of the participants: Level 1 Appeal – Level 1 is the required first step in the appeals process. The appellant submits to the Standards Process Manager a complaint in writing that describes the substantive or procedural action or inaction associated with an Organization Standard or the standards process. The appellant describes in the complaint the actual or potential adverse impact to the appellant. Assisted by any necessary staff and committee resources, the Standards Process Manager shall prepare a written response addressed to the appellant as soon as practical but not more than 45 days of receipt of the complaint. If the appellant accepts the response as a satisfactory resolution of the issue, both the complaint and response will be made a part of the public record associated with the standard. Level 2 Appeal – If after the Level 1 Appeal the appellant remains unsatisfied with the resolution, as indicated by the appellant in writing to the Standards Process Manager, the Standards Process Manager shall convene a Level 2 Appeals Panel. This panel shall consist of the Chairman of each of the three NERC standing committees and two members of the Stakeholder Committee selected by the Chairman of that Committee (five panel members total). In all cases, Appeals Panel members shall have no direct affiliation with the participants in the appeal. The Standards Process Manager shall post the complaint and other relevant materials and provide at least 30 days notice of the meeting of the Level 2 Appeals Panel. In addition to the appellant, any person that is directly and materially affected by the substantive or procedural action or inaction referenced in the complaint shall be heard by the Panel. The Panel shall not consider any expansion of the scope of the appeal that was not presented in the Level 1 Appeal. The Panel may in its decision find for the appellant and remand the issue to the Standards Committee with a statement of the issues and facts in regard to which fair and equitable action was not taken. The Panel may find against the appellant with a specific statement of the facts that demonstrate fair and equitable treatment of the appellant and the appellant’s objections. The Panel may not, however, revise, approve, disapprove, or adopt an Organization Standard, as these responsibilities remain with the Standards Committee and Board respectively. The actions of the Level 2 Appeals Panel shall be publicly posted. In addition to the foregoing, a procedural objection that has not been resolved may be submitted to the Board of Trustees for consideration at the time the Board decides whether to adopt a particular Organization Standard. The objection must be in writing, signed by an officer of the objecting entity, and contain a concise statement of the relief requested and a clear demonstration of the facts that justify that relief. The objection must be filed no later than 30 days after the announcement of the vote by the Standing Committee on the Organization Standard in question.

Organization Standards Maintenance of Organization Standards and Process Process Manual


Maintenance of Organization Standards and Process Parliamentary Procedures Except as required by this manual or other NERC documents, all meetings conducted as part of the standards process shall be guided by the latest version of Robert’s Rules of Order. Process Revisions A request to change this Organization Standards Process Manual shall begin with the preparation of a SAR and be handled using the same procedure as a request to revise an Organization Standard, with the exception of two differences in the balloting by the Standards Committee. The first difference is that a single ballot will be conducted and the results of that ballot will be binding. The second difference is that approval of revisions to the Organization Standards Process Manual shall require affirmative votes by a two thirds majority of the Standards Committee. Once approved by the Standards Committee, any proposed revisions to this manual would go to the Board of Trustees for adoption. The manual may be revised only by authority of the NERC Board of Trustees. Standards Process Accreditation NERC shall seek continuing ANSI accreditation of the standards process defined by this manual. The Standards Process Manager shall be responsible for administering the accreditation application and maintenance process. Five Year Review Each Organization Standard shall be reviewed at least once every five years from the effective date of the standard or the latest revision to the standard, whichever is the later. The review process shall be conducted in accordance with Steps 5, 7, and 8 of the standards process. As a result of this review, an Organization Standard shall be reaffirmed, revised, or withdrawn. If this review indicates a need to revise or delete the standard, a SAR shall be prepared and submitted in accordance with the standards process. The Standards Process Manager shall be responsible for administration of the five-year review of Organization Standards. Filing of Organization Standards with Regulatory Agencies At the discretion of the Board of Trustees, adopted Organization Standards may be filed with applicable regulatory agencies in the United States, Canada, and Mexico. On-line Standards Information System The Standards Process Manager shall be responsible for maintaining an electronic database of information regarding currently proposed and currently in effect Organization Standards. This information shall include current standards in effect, proposed revisions to standards, and proposed new standards. This information shall provide a record, for at a minimum the previous

Organization Standards Appendix A Process Manual


five years, of the review and approval process for each Organization Standard, including public comments received during the development and approval process. This information shall be available through public Internet access. Archived Standards Information The Standards Process Manager shall be responsible for maintaining a historical record of Organization Standards information that is no longer maintained on- line. For example, standards that expired or were replaced may be removed from the on- line system. Also, SARs that are no longer being considered in the standards process may be placed in the archived records. Archived information shall be retained indefinitely as practical, but in no case less than five years from the later of the date on which the standard was no longer in effect or the date on which the information was first recorded in the standards information system. Archived records of standards information shall be available electronically within 30 days following the receipt by the Standards Process Manager of a written request. Numbering System The Standards Process Manager shall establish and maintain a system of Identification Numbers that allow Organization Standards to be categorized and easily referenced.

Organization Standards Supporting Documents Process Manual


Supporting Documents

The following documents may be developed to support an Organization Standard. These documents may explain or facilitate implementation of standards but do not themselves contain mandatory requirements subject to compliance review. Any requirements that are mandatory shall be incorporated into the standard. For example, a procedure that must be followed as written must be incorporated into an Organization Standard. If the procedure defines one way, but not necessarily the only way, to implement a standard it is more appropriately a reference.

Type of Document Description Approval

Standard Reference Descriptive, explanatory information to support the understanding and interpretation of an Organization Standard.

Standing Committee

Standard Supplement Data forms, pro forma documents, and associated instructions that support the implementation of an Organization Standard.

Standing Committee

Procedure Step-wise instructions defining a particular process or operation. Procedures may support the implementation of an Organization Standard or satisfy another purpose consistent with the Reliability and Market Interface Principles.

Standing Committee

Practice A convention of behavior. Practices may support the implementation of an Organization Standard or satisfy another purpose consistent with the Reliability and Market Interface Principles.

Standing Committee

Training Reference Training materials that may support the implementation of an Organization Standard or satisfy another purpose consistent with the Reliability and Market Interface Principles.

Standing Committee

Technical Reference Descriptive, technical information or analysis. A technical reference may support the implementation of an Organization Standard or satisfy another purpose consistent with the Reliability and Market Interface Principles.

Standing Committee

White Paper An informal paper stating a position or concept. A white paper may be used to propose preliminary concepts for a standard or one of the documents above.

Standing Committee Approves for Publication with No Implied Approval of the Concepts or Positions in the White Paper.



Appendix A – Information in a Standard Authorization Request

The table below provides a representative example of information in a Standard Authorization Request. The Standards Process Manager shall be responsible for implementing and maintaining this form as needed to support the information requirements of the standards process.



Standard Authorization Request

Date of Request

Identification Number

Approval Date for SAR Posting

Approval Date for Development

Contact Information Name of Requester Primary Contact

Telephone Number

E-mail Address FAX Number

Type of Standard Authorization Request

New Standard

Revision to Existing Standard

Emergency Action New or Existing Standards

Withdraw Standard3

Description

Brief Description

Principle to Which Standard Applies

Entity(s) to Which Proposed or Revised Standard Applies

Purpose of Standard (Should Provide Reliability Basis for the Standard)

3 Requests to Withdraw an existing NERC Organization Standard will only require that the “Brief Description” section be completed explaining in detail why the NERC Organization Standard should be withdrawn.



Related Standards

Are you aware of any other NERC/NAERO Standards with a Similar Scope?

If yes, please provide Standard number

Are you aware of any other NERC/NAERO Standard Authorization Requests with a Similar Scope?

If yes, please provide SAR number

Will this Standard have an impact on other approved NERC/NAERO Standards?

If yes, please provide Standard number(s)

Are there related Standard Authorization Requests to address the necessary changes to existing Standards?

Please provide the SAR number if not submitted with this SAR.

Please describe any known Regional Differences

Detailed Description of Proposed Standard or Revision

Please provide a detailed description of the Standard to be developed in sufficient scope that an independent entity familiar with the industry could draft a Standard based on this description. Attach additional pages as required.

Implementation Plan

Proposed Implementation ______ days after adoption by Board of Trustees or

on _______________________

Note: Plans for implementation of the proposed standard, including any system or training requirements should be attached.

Assignments

Technical Subcommittee(s) NERC Staff

Exhibit F

Transmission Expansion: Issues and Recommendations

Transmission Adequacy Issues Task Force

Report to the NERC Planning Committee

DRAFT

September 17, 2001

Approved by NERC Planning Committee: September 28, 2001

TABLE OF CONTENTS

I. Introduction..................................................................................................... 1 II. Executive Summary ....................................................................................... 2 III. Background..................................................................................................... 3 IV Transmission Reliability and Need ................................................................ 4 V. Issues and Recommendations ...............................................................................6 Planning...................................................................................................... 6 Cost Recovery ............................................................................................ 9 Siting......................................................................................................... 11 Education.................................................................................................. 13 VI. Transmission-Related Technologies .......................................................... 15 Appendix A. Scope of the Transmission Adequacy Issues Task Force.......... 17 Appendix B: List of Sources on Transmission Issues ...................................... 19 Appendix C: Regional Transmission Interview Participants ............................ 20 Appendix D. Transmission Adequacy Issues Task Force Membership .......... 21

Draft - September 17, 2001 i

Introduction

The Transmission Adequacy Issues Task Force’s (TAITF) analysis of issues and obstacles that are impacting the planning and expansion of the transmission systems is outlined in this report. The report also presents recommendations to reduce or eliminate these obstacles to the expansion or reinforcement of the transmission systems. Particular emphasis is placed on the recommendations where NERC can play a significant role in achieving these objectives.

The deregulation of wholesale electricity supply in the electric industry has led to a number of changes, including the restructuring of the electric industry, and has created many new challenges for all market participants. In part, as a result of deregulation, a rapid expansion of one portion of the electric system generation supply has occurred. However, the expansion of the transmission systems has not been well coordinated with the generation expansion in all regions. The failure to expand transmission on a regional basis has led to congestion in various parts of the North American transmission systems, preventing the electricity market from working as efficiently at it might.

Planning new generation or new transmission requires a coordinated approach to ensure electric system reliability and efficient congestion management. A market approach to planning will require providing all transmission customers access to well-defined transmission rights and efficient price signals that show the consequences of their transmission use decisions. If a market approach is successful, the decisions of where, when, and how to relieve congestion will be driven by economic considerations in addition to reliability requirements. The issues and recommendations in this report reflect the deliberations of the Task Force as well as feedback from the NERC Planning Committee and the NERC Market Interface Committee. In addition, information from four Regional Council transmission interviews (ERCOT, MAAC, MAIN, and MAPP) provided valuable input to the Task Force.

Draft - September 17, 2001 1

Executive Summary

The reliable operation of the interconnected transmission systems in the near term is highly dependent upon coordination and proper actions by transmission system operators. In the longer term, the reliability of the interconnected transmission systems will also be highly dependent upon the location of new generation resources and the addition of new transmission facilities. With few major transmission facilities and reinforcements identified for construction over the next several years, transmission congestion is expected to increase and electricity transactions will likely continue to be curtailed. The Transmission Adequacy Issues Task Force has identified a number of key issues that are impacting the planning and construction of new transmission facilities or transmission reinforcements. The Task Force has also made a number of associated recommendations to reduce or eliminate the obstacles to transmission expansion. These recommendations focus largely on actions or activities that NERC can pursue. For areas beyond NERC’s responsibility, NERC also encourages the electric industry, the regulatory community, and others to consider a number of actions. The Task Force’s issues and recommendations pertaining to transmission expansion are grouped into the following four areas that are described in the next four sections: Planning Cost Recovery Siting Education While the issues in each section of the report are numbered and thereby represent somewhat of a general prioritization, the numbering is intended primarily to improve communications and to associate the recommended actions with the particular issues. Coordination is an underlying theme in each of these four areas. The Task Force, therefore, elected to include elements of its coordination findings within the four issue groups. Coordination is required among various stakeholder groups and regulatory bodies. Coordination is also necessary among those entities that deal with the technical elements of planning, siting, and constructing transmission facilities, including regional reliability groups and transmission entities responsible for the reliability of the bulk electric systems.


Background On October 20, 2000, Planning Committee Chairman Harlow R. Peterson appointed a Transmission Adequacy Issues Task Force comprised primarily of PC members. The creation of this Task Force was confirmed by the PC with its approval of the Task Force’s scope (Appendix A) at the November 14–15, 2000 PC meeting. The Task Force’s charge was to identify key issues or obstacles impacting the planning and expansion of the transmission systems and to recommend actions or activities that NERC, the electric industry, or others can possibly pursue to help reduce or eliminate them. Over the November 2000–February 2001 period, the Task Force reviewed, summarized, and extracted a number of issues impacting the planning and expansion of the transmission systems from several major electric industry reports (Appendix B). These reports and their reviews, through a number of Task Force conference calls, provided background on the Task Force’s assignment. As part of this process, the Task Force identified to the extent possible: industry trends in transmission expansion; issues (industry structure, regulatory framework, siting, investments in facilities, other) impacting transmission expansion; recommendations to reduce or eliminate obstacles to transmission expansion; and other miscellaneous items. In mid-January 2001, the Task Force invited representatives from each of four Regions — MAPP, MAAC, ERCOT, and MAIN — to an interview-type meeting in February 2001 to discuss each Region’s recent transmission planning and expansion activities. The Regional participants are identified in Appendix C. The industry reports and the transmission interview formed the basis for the Task Force’s preliminary findings and recommendations.

Based on comments from the NERC Planning Committee and Market Interface Committee on its preliminary findings and recommendations, a review of transmission-related technologies being explored to more fully utilize existing transmission systems and to find alternate solutions to transmission expansion, and a review of portions of the National Energy Policy Development Group’s May 2001 National Energy Policy report to the President of the United States, the Task Force completed its draft report for further Planning Committee and Market Interface Committee review in July 2001.


Transmission Reliability and Need

Among the purposes for which the North American Electric Reliability Council (NERC) was formed are the following: a) to promote the reliability and adequacy of the bulk electric supply by the electric

systems in North America, and b) to develop, implement, and, consistent with executed agreement(s) with Regional

Councils, enforce standards that provide for an adequate level of reliability of the bulk power systems in North America.

Transmission Reliability NERC addresses bulk electric system reliability by considering two basic and functional aspects of the electric system adequacy and security. – Adequacy The ability of the electric system to supply aggregate electrical

demand and energy requirements of the customers at all times, taking into account scheduled and unscheduled outages of system facilities.

– Security The ability of the electric system to withstand sudden disturbances such

as electric short circuits or unanticipated loss of system facilities. The ability of the electric transmission systems to transfer electric power among their interconnected elements and deliver power from generation sources to customers or customer demand centers may be limited by the physical and electrical characteristics of the systems including thermal, voltage, and stability limits. A basic reliability tenet in the planning and expansion of the transmission systems is that the transmission systems should be capable of delivering or transferring electric power to meet the customer demands for electricity while surviving certain critical system disturbances or contingencies by operating reliably within specified thermal, voltage, and stability limits. To ensure the reliability of the interconnected transmission systems in North America, the planning and operation of these systems must be conducted in compliance with NERC Planning and Operating Standards and Policies. The Regional Reliability Councils (Regions)and their member systems, as well as other entities responsible for the interconnected transmission systems, also may have established additional and more detailed reliability criteria appropriate to their Region or system, and these criteria must be followed as well. Transmission Need

The historical reasons for transmission system expansion have generally been tied to: a) integrating electric generation sources to serve defined customer demands in a

specified area or region,


b) providing flexibility to handle shifts in facility loadings caused by maintenance and forced outages of generation and transmission equipment,

c) sharing generating capacity through diversity in customer demands and generation

availability, and d) allowing for the economic exchange of electric power among neighboring systems

when temporary surpluses in generating capacity are available. These reasons for transmission development, expansion, and reinforcement must now be reexamined in the context of competitive electricity markets. These markets require transmission expansion not only to interconnect new generation capacity but also to provide flexibility for the delivery of that generation capacity to customers. Both the customer’s selection of supplier and the customer’s load variations with time must be considered. Transmission systems are being subjected to power flows in magnitude and directions that were not considered when the systems were planned. In many instances, these new flow patterns result in an increasing number of transmission facilities being identified as limits to electric power delivery or transfers. As indicated in the May 2001 National Energy Policy report “more electricity is being shipped longer distances over a transmission system that was initially designed only to provide limited power and reserve sharing among neighboring utilities.” Open access to the transmission systems has raised concern about the definition or justification of need for new transmission projects. In the future, the need for new transmission will likely be based on or driven by access to competitive power supplies in addition to the traditional reliability need or justification. That is, eliminating market congestion and facilitating more liquid electricity markets will be key economic factors in the justification for new transmission. As a result, reliability and commercial value, in addition to safety and environmental impact, will all be important factors assessed by transmission providers, regulators, and government entities in evaluating transmission projects. While increased competition and restructuring in the electric industry are changing many of the traditional relationships on which the reliability of the North American bulk electric systems was founded, the potential for economic gains or increased electric system flexibility should not be allowed to degrade or encroach upon the reliability of the bulk electric systems. The goal of increasing flexibility and economic choices in electric power supplies is desirable, but should not be achieved at the expense of reliability.


Planning

The following transmission planning and expansion issues deal with the definition of the need for new projects and the development of the justification to construct them. The related recommendations represent approaches to reducing or eliminating the obstacles to transmission expansion. Issues 1. Most current transmission projects are being driven by traditional localized and regional

reliability needs or by requirements to connect new generation to the interconnected bulk electric transmission systems. Transmission systems designed primarily for reliability purposes may not fully meet the needs of today’s competitive electricity markets. The risks and consequences of insufficient transmission capability will need to be evaluated and communicated to electricity customers.

2. In some areas, significant new transmission expansion is required to connect confirmed new

generation, to comply with state mandates to enable retail choice, or to provide for growth in customer demands. These complex and rapidly evolving requirements are overwhelming the transmission planning process such that there is not enough time to develop optimal transmission plans.

3. There is an increasing need to focus project commitment decisions on the economics of the

project in addition to reliability benefits. Because the electricity supply/demand market operates primarily in the short term and few longer-term transmission service commitments are made, the revenue stream necessary to justify a major transmission project from a business perspective is often difficult to identify. Further, as a result of cost recovery issues, fewer projects are moving into the certification or licensing process. (See Cost Recovery section.)

4. In many areas, transmission margins are becoming so thin that construction outages required to

place new transmission facilities in service are very difficult or impossible to schedule. These situations limit the practical construction options available and increase the cost of the project.

5. The number of new generation connection requests and transmission service requests are

overwhelming the available planning manpower resources throughout the industry. Some generation requests involve studies of multiple sites because the developers have little information to judge which locations are feasible from a transmission capability perspective. In some cases, the study requests involve an “unreasonable or inordinate” number of alternatives.

6. Generation interconnection locations are often based upon generation developer needs, rather

than transmission system impacts, and can lead to inefficient transmission expansion. Therefore, the uncoordinated siting of generation and the development of transmission projects could also result in some transmission being constructed unnecessarily. The probability of generation negating the need for transmission is a realistic scenario in some cases as the siting and construction of new combustion turbine generators generally has a shorter lead time than the construction of new transmission.


7. Generation interconnection planning is complicated by differences in processes and procedures across electric system boundaries and the differing roles in the planning process of various entities across those boundaries. In the short term, uncertainties with respect to evolving industry structures and participants make it difficult to establish coordination procedures related to planning across regional and neighboring system interfaces. Until the participants, the specific industry structures, and the planning processes that will be used are better defined, it is difficult to initiate coordination activities.

8. Analytical tools and the expertise to apply those tools are not keeping up with current demands.

Today, planning continues to be largely deterministic because transmission customers and providers lack robust probabilistic tools to help evaluate the risks of insufficient transmission capability.

Recommendations 1. NERC should assure that its Planning Standards for reliability are strictly enforced. The need

and justification for transmission projects must be clearly articulated and communicated to the decision makers and the public to avoid delays or jeopardizing project approval. (Planning Issues 1, 3, and 6)

2. NERC should expand its system adequacy definition to incorporate economic uses of the

transmission systems beyond the requirements imposed by its reliability Planning Standards. However, all transmission system expansions designed to meet the needs of the electricity market, while economically justified, must also meet the NERC reliability standards. (Planning Issue 1)

3. NERC and those responsible for the reliability of the transmission systems should survey the

generation developers, the load serving entities, and the electricity marketers as to their information needs regarding future transmission capacity and other market requirements. Such information, if appropriate from a non-competitive perspective, could be provided and updated periodically to help focus generator interconnection and transmission service requests. It is envisioned that this information might include: a) identification of areas with little generation relative to demand, b) areas saturated with generation, c) guidelines relating plant size and transmission outlet capability that would demonstrate how larger plants need to be connected to higher voltage systems, and d) technical data for generation developers to make their own preliminary assessment of transmission reliability (steady state, stability, and short circuit analyses). (Planning Issues 2 and 5)

4. The transmission owning entities responsible for the reliability of the interconnected

transmission systems should periodically review and document their future transmission corridor requirements with appropriate regulatory bodies. (Planning Issue 2)

5. NERC should provide a forum for the investigation, development, and application of new and

existing transmission planning tools that can enhance planning decisions and streamline the planning process. It should also support the collection of the necessary data to develop and implement such tools. Some examples of relevant tools include: a) probabilistic risk assessment tools that can assist in making business decisions on new projects, and b) system modeling tools that could provide reasonable scenarios of future power flow patterns to aid in


developing longer-range plans and the business case for justifying major transmission projects. (Planning Issues 3 and 8)

6. Major transmission projects, where possible, should be planned with appropriate margin to

provide capacity to meet system needs beyond the current or near-term system requirements. Such margins may provide the flexibility required to maintain reliability during maintenance and construction outages, and may also help conserve and make optimal use of difficult to obtain right-of-way corridors. These transmission margins could be achieved, for example, by using larger conductors, providing space for additional circuits on structures (e.g., double circuit structures) or on the right of way, and employing tower designs readily adaptable to higher voltage operation. NERC should support the implementation of such margins where practical. (Planning Issue 4)

7. Formal coordination procedures among neighboring Regions, systems, and other entities

should be developed by the regional transmission organizations (RTOs) and regional reliability organizations to avoid case-by-case resolution of the planning and expansion of the transmission systems. The coordination process should integrate the planning of generation facilities with transmission. (Planning Issues 6 and 7)


Cost Recovery

A key factor that has been affecting the expansion of the transmission systems is the lack of a clear policy regarding cost recovery of the investments needed to provide for reliable and efficient transmission systems. This lack of a clear policy concerning transmission investments is one of the factors contributing to the inefficiencies in the electricity market.

NERC does not have the authority to order the expansion of generation or transmission facilities, nor does NERC have the authority to guarantee the cost recovery of the investments needed to ensure that an efficient electricity market occurs. NERC, however, can identify issues that should be considered during the development of a cost recovery policy and encourage the development of cost recovery policies to avoid a degradation in the reliability of electric service in North America. Issues 1. Some entities responsible for the reliability of the interconnected systems are concerned

about the recovery of transmission investment at a fair rate of return. 2. Regulatory disallowances, in some cases after receiving approval via a certificate of

convenience and necessity (CCN), could make transmission investments unprofitable and thereby risky investments.

3. In some cases, cost responsibility for transmission additions and upgrades is unclear.

Confusion exists among stakeholders concerning how much of the cost of transmission system expansion should be borne by specific stakeholders versus how much expansion cost should be borne by the market as a whole.

Recommendations 1. Consistent with FERC Order 2000, NERC should encourage regulators to authorize cost

recovery mechanisms that encourage investment in transmission facilities. Further, where regional transmission projects are involved, regional cost recovery mechanisms need to be developed. These mechanisms include, but are not limited to, reduced amortization periods, accelerated depreciation, or the allowance for negotiated arrangements. They also need to consider rates of return that recognize the risks and difficulties associated with new transmission projects as well as the competing uses of capital.

The May 2001 National Energy Policy report directs “the Secretary of Energy to work with FERC to relieve transmission constraints by encouraging the use of incentive rate-making proposals.” Incentive rates is one way some transmission owners have proposed that may lead to an investment climate which will encourage new investment in transmission. (Cost Recovery Issue 1)


2. NERC should encourage regulators to adopt clear and consistent rules for the recovery of transmission investments at reasonable and pre-determined rates of return. (Cost Recovery Issues 1 and 2)

3. NERC should facilitate the development of the technical basis for determining the distinction

between system upgrades and generation interconnection facilities. Regulators should use this information to review current policies and eliminate confusion on the cost responsibility for transmission investment. (Cost Recovery Issue 3)


Siting

Siting and routing issues represent significant obstacles to the expansion of the transmission systems. These issues revolve around the difficulties of acquiring regulatory approval and rights-of-way (ROWs) for transmission lines. Issues 1. The fact that electricity markets are increasingly regional rather than local makes the siting

and routing of transmission more difficult since multiple regulatory jurisdictions are involved. In some cases, the local regulators and the general public, whose properties are impacted by the transmission facilities, may not see any direct benefits from such regional projects.

2. ROW acquisition is often strongly opposed by landowners and public interest groups based

upon health, environmental, and other concerns. This opposition can result in lengthy project delays or cancellation.

3. The failure to clearly convey the need and justification of a transmission project to the

regulatory and public entities impedes the permitting process for new transmission projects. The permitting process becomes even more imposing and complex when transmission lines cross state (provincial) lines, federal lands, or international boundaries, where several regulatory bodies, each with different requirements or perceptions of the project’s need and usefulness, are involved.

4. Some regulatory agencies responsible for managing the siting process have inadequate

resources to complete their investigations in a timely manner.

Recommendations 1. NERC should sponsor a forum, in conjunction with the National Association of Regulatory

Utility Commissioners (and other appropriate state entities), the Federal Energy Regulatory Commission, and applicable Canadian regulatory bodies, to develop generalized siting and routing guidelines for transmission projects that cross state (provincial) lines, federal lands, and international borders. Among other issues, these guidelines should address:

• roles of state (provincial) and federal authorities regarding siting and route selection, • definition of the study area,

• number of alternate routes to be studied in the routing process, • standardization of procedures among different jurisdictions, and

• processes to better educate the general public, public interest groups, and regulatory bodies on the need and benefits of new transmission, and environmental concerns. (Siting Issues 1, 2, and 3)


2. The transmission system planning process must encourage greater regulatory and stakeholder

participation. This participation must occur early in the planning process as opposed to waiting until the certification or licensing phase. (Siting Issue 3)

3. Even though transmission expansion may not be required for several years into the future, the

certification or licensing process should allow for the identification and acquisition of critical ROWs or corridors for transmission projects as early as possible. Transmission providers should be permitted to acquire and recover costs for future use corridors. (Siting Issues 1 and 3)

4. Regulatory agencies should be adequately staffed or engage outside consultants, as needed,

to implement the siting process in a timely fashion. Siting laws should permit the applicant entities to fund such consultants. (Siting Issue 4)


Education

Understanding and expertise in the engineering aspects of electric power systems on the part of those that authorize, regulate, invest in, and use transmission are necessary to properly develop policy and evaluate transmission project viability. Wide-ranging and continuing education of all participants involved in transmission projects, including transmission planners and executives, regulators, environmentalists, generators, power marketers, and other users, will be a key ingredient in developing and implementing projects successfully. Issues 1. In some cases, insufficient understanding and lack of expertise at local, state, and federal

regulatory agencies of current trends and issues within the electric industry as a whole, including knowledge of the technical impact of deregulation and FERC orders, are major contributors to project delays and even abandonment.

2. The electric industry’s failure in some cases to properly educate the regulators and the public

on the need for transmission projects and the consequences of inadequate transmission have led to differing viewpoints, inactivity, and poor decision making, and ultimately higher costs to the customer.

3. Limited availability of engineers with power system training causes concern for the ability to

plan, construct, operate, and maintain the electrical system infrastructure of the future. 4. The ability of the educational system to produce new power system engineers has been

drastically reduced due, in many cases, to program reduction or elimination. 5. Transmission system terminology and definitions vary across the NERC Interconnections,

contributing to confusion and in some instances conflict. Recommendations 1. NERC, in collaboration with other industry groups, should develop and update generic

course materials and presentations on the planning and operation of the transmission systems for the regulators and the public in light of today’s environment of the industry’s change to deregulation and vertical disintegration. (Education Issues 1 and 2)

2. Early in the planning process, project sponsors and other associated parties should develop

and present project specific presentations targeted to the public on the planning, justification, environmental effects, and operation of proposed transmission projects. (Education Issues 1 and 2)

3. NERC should establish a pool of technical advisors or experts that can be engaged by

regulatory and governmental authorities in their policy formulation and decision making activities on transmission related issues. (Education Issues 1, 2, and 4)


4. NERC, through its membership, should encourage and promote power system engineering programs at local colleges and universities, including sponsoring cooperative and work-study programs at member companies. (Education Issues 3 and 4)

5. NERC should encourage the IEEE Power Engineering Society to perform an analysis of the

status of power engineering education and the power engineering job market to provide a strategic look at existing and future capabilities and needs. This analysis should include a review of salary implications. A report of this analysis will be disseminated by NERC to its members. (Education Issues 3 and 4)

6. NERC should continue to develop and communicate standard language and measurements

appropriate to the transmission systems. (Education Issue 5)


Transmission-Related Technologies

The open-access use of the transmission systems for purposes for which they were not planned has loaded these systems to their limits in some areas. In considering solutions that will address these limitations for the near- and longer-term delivery of reliable electric power, applications of technologies such as HVDC transmission, flexible AC transmission system (FACTS) devices, and superconductivity are being explored to fully utilize existing transmission systems and to find alternate solutions to transmission expansion. HVDC Transmission HVDC transmission has been an economically competitive alternative to high voltage AC transmission for applications involving long distances. The technical complexity and high cost of tapping a HVDC transmission line has made it less attractive for network applications. However, recent advances in converter technology have made HVDC a viable alternative for serving small remote load centers (up to 200 MW). Applications of HVDC transmission must overcome similar hurdles (such as environ-mental concerns, right-of-way acquisition, etc.) as those associated with AC transmission. The beneficiaries of the HVDC technology will be those communities and towns located large distances from the electrical grid (generation). Additionally, HVDC transmission may be an effective alternative to AC transmission for increasing the power transfer capability of existing right-of-way corridors. HVDC (back-to-back or short DC links) technology is also ideally suited to interconnect large AC networks, networks of different frequencies, and for underwater cable applications. Flexible AC Transmission Systems FACTS technology in some cases can increase the utilization of the capacity of an existing transmission line (within its thermal rating) by providing precise adjustments of transmission line voltage, impedance, or phase angle to control real and reactive power flows. FACTS devices can also improve system stability including low frequency power system oscillation damping. Although FACTS devices have generally been applied to optimize transmission performance and security, case specific analysis is required to assess the impact of the FACTS devices on transmission reliability relative to transmission line additions. Superconducting Transmission

Superconductivity was discovered at the beginning of the 20th century. In 1986, the discovery of ceramic-based high temperature superconductors (HTS) opened the possibility of applying this new technology to transmission cables, power transformers, fault current limiters, and other power devices. The ability to achieve the superconductivity state by using inexpensive liquid nitrogen, rather than liquid helium, as required by the original superconductors, has made


this technology more attractive for possible application to the electric industry. Such applications include: • HTS cables that may be capable of carrying 3 to 5 times more power than

conventional cables, • HTS windings and tap-changers that may transform existing oil-filled power

transformers into compact, environmentally friendly (i.e. dry), and highly efficient devices, and

• HTS fault current limiters that may provide a more economical solution to limiting

fault current levels than conventional technology. HTS technology may be a viable “local area” alternative in the next 15 to 20 years, but at best it will only play a small part in the expansion of the bulk power transmission systems. The May 2001 National Energy Policy report recommends expanded research and development on transmission superconductivity. Summary: Transmission-Related Technologies Advances in technology could play an important role in addressing and providing solutions for system constraints such as voltage and stability. However, the above technologies need further research for widespread cost effective applications. HVDC transmission is comparable to conventional AC transmission with regard to requirements for land and right-of-way requirements and has been used in a number of significant commercial applications at various high voltage levels worldwide. Application of FACTS devices allows more optimal utilization of existing transmission systems and improves operating flexibility and system stability. HTS products are promising but are expected to only play a small role in local areas. These new technologies are expected to provide increased utilization of existing transmission facilities, however, they should not be viewed as a viable alternative or wholesale replacement for transmission system expansion.


Appendix A

Scope of the Transmission Adequacy Issues Task Force

Background NERC’s Reliability Assessment 2000–2009 report indicates that in the near term (2000–2004), transmission system reliability in the United States, Canada, and the northern portion of Baja California Norte, Mexico, is expected to be satisfactory. However, this reliability is highly dependent upon coordination with surrounding systems and proper transmission system operator actions. Few major transmission system facility additions are planned for this period. In the long term (2005–2009), the reliability of the interconnected transmission systems will be highly dependent upon the location of new generating resources. Unless proper incentives can be developed to encourage investment in new transmission facilities and siting problems can be resolved, few new transmission facilities and reinforcements are expected to be constructed. Based on discussions at recent NERC Planning Committee meetings, the PC needs to investigate, identify, and understand the key issues that influence and impact the planning and construction of new transmission facilities or transmission reinforcements today and in the future. The PC also needs to determine if it can initiate actions or activities to help alleviate obstacles to the planning and construction of new (or reinforced) transmission facilities. Purpose(s) Review the status and recent trends in the planning and construction of new transmission facilities or transmission reinforcements. Investigate and identify the key issues in the near term and longer range that impact or are expected to impact the planning and construction of transmission facilities. Recommend actions to help alleviate obstacles to the planning and construction of needed new (or reinforced) transmission facilities from either a reliability or electricity market perspective. Scope of Activities

1. Review the data collected on transmission in connection with NERC’s ten-year and seasonal reliability assessments to determine the status and recent trends in the planning and construction of transmission facilities. Summarize the key issues identified as impacting or influencing the planning and construction of transmission facilities.

2. Search out other sources related to transmission that may be helpful in identifying the key

issues that are impacting the planning and construction of new (or reinforced) transmission facilities.


3. Conduct surveys or interviews with the Regions on transmission planning and those entities that are constructing, or recently announced construction of, new (or reinforced) transmission facilities.

4. Investigate current approaches or new tools being used, or available, to plan transmission

facilities and their relationship with generation resources. 5. Prepare a final report that summarizes transmission planning and construction trends and

factors impacting the planning and construction of transmission facilities, and recommend actions that the electric industry and/or the PC can pursue to help alleviate obstacles to the planning and construction of new (or reinforced) transmission facilities.

Membership

• Chairman • 8–10 Planning Committee members or their representatives

Reporting Responsible to the NERC Planning Committee. Timeframe or Schedule

1. November 2000 PC meeting — Finalize Task Force’s scope of activities. 2. March 2001 PC meeting — Provide status report and a preliminary list of key issues

impacting the planning and construction of transmission facilities for review and comment by the PC.

3. July 2001 PC meeting — Present final report and recommended actions that the electric

industry and/or the PC can pursue for implementation that will help alleviate obstacles to the planning and construction of new (or reinforced) transmission facilities.

Approved by Planning Committee: November 14, 2000


Appendix B

List of Sources on Transmission Issues The following is a list of sources related to transmission that were reviewed by the TAITF to identify the key issues that are impacting the planning and expansion of transmission facilities.

♦ Final (integration) report of “Market-Reliability Interface Collaborative Planning Initiatives” supported by NERC, including the six search conference reports:

– Atlanta (April 12–14, 2000) – Philadelphia (April 17–19, 2000) – Dallas (April 25–27, 2000) – Chicago (May 2–4, 2000) – San Francisco (May 9–11, 2000) – Toronto (May 31–June 2, 2000) ♦ Transmission sections in the NERC Reliability Assessment Reports from 1997 forward. ♦ Presentations from the “Resource Adequacy Planning Seminars” at the July 2000 NERC Adequacy

(now Planning) Committee meeting ♦ “Expanding U.S. Transmission Capacity,” Eric Hirst for Edison Electric Institute, Washington,

D.C., July 2000. ♦ “The Competitive Effects of Transmission Capacity in a Deregulated Electricity Industry,” Severn

Borenstein, James Bushnell, and Steven Stoft, RAND Journal of Economics, Vol. 31, No. 2, Summer 2000, pp. 294–325.

♦ “The Future of Electric Transmission in the United States — A Vision for Transmission as a

Vibrant, Stand-Alone, For-Profit Business,” PA Consulting Group, Washington, D.C., January 2001.

♦ “FACTS Technology Development: An Update,” Abdel-Aty Edris, (Electric Power Research

Institute), IEEE Power Engineering Review, Vol. 20, No. 3, March 2000, pp. 4–9. ♦ “Summary of EPRI’s FACTS System Studies,” Rambabu Adapa, Electric Power Research Institute. ♦ “Power Precision with UPFC,” Taylor Moore, EPRI Journal, November/December 1998, pp 18–23. ♦ “Highlights of Principal Transmission Technologies in Use or Planned by AEP (including series

capacitors, series reactors, static var compensators (SVCs), unified power flow controllers (UPFCs), static compensators (STATCOMs), and high voltage direct current (HDVC) projects),” Bernie Pasternack, American Electric Power, April 27, 2001.

♦ “America’s Energy Infrastructure: A Comprehensive Delivery System,” Chapter 7 of the National

Energy Policy Development Group’s National Energy Policy report to the President of the United States, May 17, 2001.


TAITF Regional Transmission Interview Participants

February 27, 2001 — 10 a.m. to 4 p.m. Orlando, Florida

ERCOT

Kenneth A. Donohoo Manager of System Planning, Technical Operations ERCOT [email protected] 512-248-3003 MAAC

Steven R. Herling General Manager, System Coordination Division PJM Interconnection, L.L.C. [email protected] 610-666-8834

Kenneth S. Seiler (Observer) Senior Engineer, System Planning Department PJM Interconnection, L.L.C. [email protected] 610-666-4410 MAIN Scott Barnhart American Transmission Company [email protected] 262-506-6814

Kirit Shah Ameren Services Company [email protected] 314-554-3542

Tom Wiedman (Observer) Exelon Corporation [email protected] 708-410-5902 MAPP

Ron W. Mazur Interconnections & Grid Supply Transmission Planning Engineer Manitoba Hydro [email protected] 204-474-3113

Draft - September 17, 2001

Appendix C

20

Appendix D

TRANSMISSION ADEQUACY ISSUES TASK FORCE ([email protected]) Bernard M. Pasternack (Chairman) Director - Transmission Planning American Electric Power 825 Tech Center Drive Gahanna, OH 43230-8250 Phone: 614-552-1600 Fax: 614-552-1676 Email: [email protected]

Richard A. Wodyka (RRO-MAAC) Executive Vice President and COO PJM Interconnection, L.L.C. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, PA 19403-2497 Phone: 610-666-8853 Fax: 610-666-2296 Email: [email protected] Donald R. Volzka (RRO-MAIN) Manager, Transmission Planning Wisconsin Electric Power Company W237 N1500 Busse Road Waukesha, WI 53188 Phone: 262-574-6050 Fax: 262-544-7556 Email: [email protected] Ken Kuyper (RRO-MAPP) Senior Vice President Engineering & System Operations Corn Belt Power Cooperative P.O. Box 508 Humboldt, IA 50548 Phone: 515-332-2571 Fax: 515-332-1375 Email: [email protected] Glenn B. Ross (RRO-SERC) Director Transmission Policy Virginia Power 2400 Grayland Avenue Richmond, VA 23220-5260 Phone: 804-257-4049 Fax: 804-257-4086 Email: [email protected]

Ajay Garg (RRO-Canada East) Sr. Advisor Network Strategy Ontario Hydro Networks 483 Bay Street, 15-A6, NT Toronto, Ontario M5G 2P5 Phone: 416-345-5420 Fax: 416-345-5424 E-mail: [email protected] Ron W. Mazur (Canada) Interconnections & Grid Supply Transmission Planning Engineer System Planning Department Manitoba Hydro P.O. Box 815, 820 Taylor Avenue Winnipeg, Manitoba R3C 2P4 Phone: 204-474-3113 Fax: 204-477-4606 E-mail: [email protected] Erik Westman (Federal) Transmission Risk Manager Bonneville Power Administration Transmission Business Line 5411 N.E. Highway 99 P.O. Box 491 TOP/DITT2 Vancouver, WA 98666-0491 Phone: 360-418-8680 Fax: 360-418-8376 Email: [email protected] Scott M. Helyer (IPP) Manager of Transmission and Marketing Services Tenaska, Inc. 2000 East Lamar Boulevard, Suite 430 Arlington, TX 76006 Phone: 817-462-1512 Fax: 817-462-1510 Email: [email protected]

TRANSMISSION ADEQUACY ISSUES TASK FORCE (cont)


Gene Anderson (State/Municipal) Director - Engineering Oklahoma Municipal Power Authority 7996 East 147 Road Calvin, OK 74531 Phone: 405-645-2280 Fax: 405-645-2280 Email: [email protected] Kenneth P. Linder (EEI Observer)a Group Director, Energy Delivery Edison Electric Institute 701 Pennsylvania Avenue, N.W. Washington, DC 20004 Phone: 202-508-5725 Fax: 202-508-5445 E-mail: [email protected] William H. White (BOT Observer) Wedge Group Inc. 1415 Louisiana Street Suite 3000 Houston, TX 77002 Phone: 713-739-6555 Fax: 713-520-1041 E-mail: [email protected] Virginia C. Sulzberger (Staff Coordinator) Director-Engineering North American Electric Reliability Council 116-390 Village Boulevard Princeton, NJ 08540 Phone: 609-452-8060 Fax: 609-452-9550 E-mail: [email protected] a) Kenneth P. Linder was initially involved with the Task Force, but retired from EEI prior to the completion of the

report.
