Reliability TF Final Report

Electric System Reliability Task Force Completes Final Report

On Tuesday, September 29, the Secretary of Energy Advisory Board’s (SEAB) Task Force on Electric System Reliability conducted its final meeting in Washington, DC and approved its final report.

The Task Force’s final 150 page report, “Maintaining Reliability in a Competitive U.S. Electricity Industry: Final Report of the Task Force on Electric System Reliability,” dated September 29, 1998, addresses the critical institutional, technical and policy issues related to maintaining bulk-power system reliability in the context of a more competitive electric industry. It will be submitted to the Chairman of the Secretary of Energy Advisory Board and Secretary Richardson following the incorporation of the final Task Force review comments.

Printed copies of the Report can be obtained from Richard Burrow, SEAB, (202/586-1709 or

Inquiries regarding the Report can be directed to Paul Carrier (202/586-5659 or

Here is a Reuters news story about the report:

Competition won’t hurt power reliability, DOE told

WASHINGTON, Sept 29 (Reuters) – A Department of Energy advisory panel on Tuesday said opening the nation’s bulk-power markets to competition should not damage reliability of electric supply, although deregulation is a complex task.

Ending a 21-month investigation, the DOE task force concluded that the “viability and vigor of commercial markets must not be unnecessarily restricted,” and market forces now being implemented depend on fair and open access to the transmission grid.
“The traditional reliability institutions and processes that have served the nation well in the past need to be modified to ensure the reliability is maintained in a competitively neutral fashion,” the task force report said.

The group, officially called the Secretary of Energy Advisory Board’s Task Force on Electric System Reliability, was formed to address the question of whether consumers would be able to count on electricity service after restructuring.

The task force began its work as a result of concerns raised after power outages in Western states during the summer of 1996. It is chaired by Dr. Philip Sharp, a lecturer in public policy at Harvard’s Kennedy School of Government.

At the time the task force was formed, the DOE asked the group to define an agenda “to address relevant technology development and analysis tools, control schemes, operating practices and data requirements for ensuring reliability under changing industry structure and regulation.”

The report also said there is uncertainty regarding statutory and regulatory authority over reliability management, which was being exacerbated by the unbundling of vertically integrated utility functions.

The group said commercial markets should develop economic practices consistent with the mutual interests of the participants, ensuring grid reliability maintenance.

The role of the North American Electric Reliability Council (NERC) must also adapt to an increasingly decentralized and competitive industry, the report said. The NERC represents wholesale power systems in 10 regions in the U.S. and most of Canada.

Other findings praised the implementation of Independent System Operators, and said competitive markets should be created for ancillary services, like load following, spinning reserve and loss replacement.

Of the numerous recommendations supplied by the task force, the report highlighted the group’s confidence that the Federal Energy Regulatory Commission and a restructured North American Electric Reliability Organization can maintain performance.

During the transition from monopoly markets to open competition, the task force said electric utilities should open their transmission systems to others and in many cases divest their generating assets.

FERC Conf. on ISOs

On Friday, FERC announced it will hold a conference on policies regarding ISOs. Here is the notice in its entirety, as taken from the FERC CIPS online system, at

For future reference, the FERC website is at:



Inquiry Concerning the )
Commission’s Policy on ) Docket No. PL98-5-000
Independent System Operators )

(March 13, 1998)

The Federal Energy Regulatory Commission (Commission) hereby announces that it will convene a public conference to discuss its policies concerning Independent System Operators (ISOs). The conference will be held on April 15-16, 1998. Primarily, the Commission intends to examine the future of ISOs in administering the electric transmission grid on a regional basis. It wishes to examine whether any changes to the Commission’s policies that affect the development of ISOs are appropriate in order to promote competition and reliability in bulk power markets. The Commission expects to address issues pertaining to the formation and responsibilities of ISOs, whether ISOs can serve as an effective vehicle for further industry reform, and the appropriate roles for federal and state regulators in ISO development.

I. Introduction

In Order Nos. 888 and 889 and their progeny (1) , the Commission established the fundamental principles of non- discriminatory open access transmission services. Nevertheless, many issues remain to be addressed if the Nation is to fully realize the benefits of open access and more competitive electric markets. The formation of regional ISOs may facilitate achievement of the Commission’s pro-competitive goals.

(1) See Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities; and Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 Fed. Reg. 21,540 (1996), FERC Stats. & Regs. 31,036 (1996), order on reh’g, Order No. 888-A, 62 Fed Reg. 12,274 (1997), FERC Stats. & Regs. 31,048 (1997), order on reh’g, Order No. 888-B, 81 FERC 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC 61,046 (1998). Open-Access Same-Time Information System and Standards of Conduct, Order No. 889, 61 Fed. Reg. 21,737 (1996), FERC Stats. & Regs. 31,035 (1996), order on reh’g, Order No. 889-A, 62 Fed. Reg. 12,484 (1997), FERC Stats. & Regs. 31,049 (1997), order on reh’g, Order No. 889-B, 81 FERC 61,253 (1997).

In the wake of the unprecedented restructuring taking place in the electric industry, the Commission has received several proposals for forming ISOs and a number of regions are also in the process of developing ISO proposals. The Commission has approved ISOs in California, the Pennsylvania-New Jersey-Maryland Interconnection (PJM), and for the New England Power Pool (New England). In addition, proposals have been filed for creating ISOs in the Midwest and New York. Utilities and other market participants in the Electric Reliability Council of Texas have also formed an independent system administrator. Members of the Mid Continent Area Power Pool and the Southwest Power Pool are discussing respective ISO proposals. In the Pacific Northwest, utilities have been involved in negotiations intended to lead to the formation of an ISO (Indego). Also, utilities in New Mexico, Arizona, and Nevada have agreed to pursue development of an ISO (Desert Star). In addition, 11 investor-owned utilities from Ohio to the District of Columbia have signed a memorandum of understanding to explore the creation of an independent regional transmission entity.

This activity, and the growing popularity of the ISO concept, presents important and even urgent questions involving the appropriate function and organization of an ISO, whether the Commission should be more active or prescriptive in this area, and whether the pro-competition goals of Commission Order Nos. 888 and 889 can be further advanced with ISOs. We note that 11 state commissions have recently filed a petition in Docket No. PL98-3-000 suggesting that the Commission generically address ISO issues.

Although the Commission has not prescribed a single approach to ISOs, it has provided significant guidance regarding the proper formation and functions of ISOs. Given the dramatic changes taking place in both wholesale and retail electric markets and the many proposals under consideration with respect to the creation of ISOs or other transmission entities, such as transmission-only utilities, it is time for the Commission to take stock of its policies in order to determine whether they appropriately support our dual goals of eliminating undue discrimination and promoting competition in electric power markets. Accordingly, the discussion below provides a description of topic areas that we would like to explore at the conference for purposes of refining our ISO policies.

II. Panels

The Commission will organize the conference according to the following panel discussions. Appended to this notice is an extensive list of questions and topics assembled by Commission staff for each panel discussion. Participants will find it a general indication of the scope of the Commission’s interest in relation to each panel. The Commission also invites interested parties to address their written comments to the questions listed as well as to any related ISO matters of generic interest.


Panel 1 Basic Structure and Role

What will be the significance of the ISO’s role in the evolution of wholesale and retail electric markets? Should the ISO control some or all aspects of grid operations in order to promote competition in wholesale and retail power markets? Must the ISO be a control area operator?

Panel 2 Regulation, Governance, and Independence

How should ISOs be formed, governed, and regulated, given the current and foreseeable restructuring of the electric industry?


Panel 3 Role of States

What is the appropriate role for states in the oversight of single-state and multi-state ISOs?

Panel 4 ISOs and Reliability

Can the formation of regional ISOs promote or enhance the reliability or security of the regional grid?

Panel 5 ISOs and Transmission Pricing

How might ISOs facilitate transmission pricing reform?

Panel 6 ISOs and Market Monitoring

Should ISOs have monitoring and sanctioning functions and, if so, can they be sufficiently independent to enable the Commission to rely upon their processes?

Panel 7 ISOs and FERC Regulation

Should the Commission require, to the extent it has the authority to require, transmission owners to form or join an ISO in the interest of preventing undue discrimination, mitigating market power, completing a nascent regional ISO, or achieving any other benefits?

III. Participation In Conference

The Commission believes that it would be beneficial at this juncture to further explore our transmission policies. To that end, we announce today a conference, as discussed above, to examine our current policies on ISOs and any appropriate changes to those policies to further our pro-competitive goals. The conference will take place on April 15-16, 1998, at the offices of the Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426. The conference will commence at 1:30 p.m. on April 15 and at 9:30 a.m. on April 16, and will be open to all interested persons.

Persons wishing to speak at the conference must submit a request to make a statement in Docket No. PL98-5-000. The request should clearly specify the name of the person desiring to speak and the party or parties the speaker represents. The request must also include a brief synopsis (not to exceed three pages) of the issue or issues the speaker wishes to address. All requests must be filed with the Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426, on or before March 31, 1998. The Commission may also contact industry experts to participate in the conference. The Commission will issue a further notice listing the speakers and panels for the conference.
In addition, all interested persons are invited to submit written comments (not to exceed 10 pages) addressing topics to be discussed at the conference. Comments must also be filed on or before March 31, 1998, in Docket No. PL98-5-000. After the conference, interested persons may also submit written comments, with all such comments due on or before May 1, 1998. All comments will be placed in the Commission’s public files and will be available for inspection or copying in the Commission’s Public Reference Room during normal business hours. Comments are also accessible via the Commission’s Records Information Management System (RIMS).

If there is sufficient interest, the Capitol Connection will broadcast the technical conference on April 15-16, 1998, to interested persons. Persons interested in receiving the broadcast for a fee should contact Shirley Al-Jarani at the Capitol Connection (703)993-3100 no later than April 3, 1998.

In addition, National Narrowcast Network’s Hearings-On-the Line service covers all FERC meetings live by telephone so that anyone can listen at their desk, from their homes, or from any phone without special equipment. Call (202) 966-2211 for details. Billing is based on time on-line.



Panel 1 Basic Structure and Role

What is the optimal size of an ISO? What factors (e.g., transmission technology, legal/jurisdictional distinctions, reliability councils) should affect the size of an ISO?

What are appropriate ISO operational responsibilities? Should the ISO operate SCADA (supervisory control and data acquisition) systems, switches, reactive power devices, transformer switching, phase shifters, and other transmission control equipment? Should the ISO control transmission facility maintenance schedules? Should the ISO control generation facilities that provide ancillary services, such as reactive power from generation, regulation and operating reserves? Should the ISO be able to direct the generation dispatch decisions of control area operators if the ISO itself is not a control area operator? Should the Commission further define the operational features of an ISO (i.e., should the Commission specify additional standards that define what is meant by an effective system operation and control), or should we allow substantial regional variation? What is the appropriate role for an ISO with regard to grid planning and expansion?
To ensure non-discriminatory transmission access, must an ISO be a control area operator? If there is a requirement that an ISO be a single control area operator and that is not feasible or cost-effective over a large area, would the result be an ISO that is too small to achieve other efficiencies like the elimination of pancaked transmission rates? Would a requirement that an ISO be a control area operator enhance competition and lower barriers to entry in the generation market? Does an ISO member that is also a control area operator have access to information that gives it an unfair advantage if it is also a market participant?

Some industry participants question whether ISOs will be permanent institutions or whether they are only transitional. Are ISOs merely part of a transitional phase for the electric industry or will ISOs be a permanent fixture in the industry structure for the foreseeable future? Is an ISO a stepping-stone to the independent regional transmission grid company? Should ISOs be designed consistent with the possible evolution to a regional gridco (i.e., a company that both owns and operates the high voltage grid)? Are there features of ISOs (e.g., stakeholder boards, not-for-profit status, ISOs serving as the operator of the PX) that will either enhance or inhibit their possible evolution into gridcos? What changes in ISO structure would be necessary to enable an ISO to more easily evolve into a gridco? Is a gridco (either for-profit or non-profit) preferable to a non-profit ISO that does not own transmission facilities?

Should the Commission encourage the formation of other transmission entities, i.e., private for-profit or government owned transmission entities? Would other types of transmission entities be better suited to sustain competition?

Panel 2 Regulation, Governance, and Independence

The Commission has not mandated a specific form of ISO governance, although it has emphasized that independence of the ISO “is the bedrock upon which the ISO must be built if stakeholders are to have confidence that it will function in a manner consistent with this Commission’s pro-competitive goals.” (2) In addition, the Commission has stressed that expertise is also critical, since transmission owners would be understandably reluctant to turn over control of their transmission assets to an operator that lacks the necessary operational expertise.

(2) Atlantic City Electric Company, et al., 77 FERC 61,148 at 61,574 (1996).

The recent trend has been toward a two-tiered form of governance: an independent non-stakeholder board, whose members are not affiliated with market participants, advised by committees of stakeholders. Within the ISO, the independent non- stakeholder board has the ultimate decision-making authority. Some have suggested that the two-tiered approach seems to have the advantage of combining independence with expertise. The two- tiered approach has been adopted in New England and PJM.

Should the Commission encourage or define a particular form of ISO governance beyond the independence principle? Should the Commission establish additional standards in the area of governance, but allow reasonable variations on a regional basis? Because transmission system owners do not have a controlling vote in an ISO, should the owners be allowed to establish any ISO rules that cannot be changed by vote of the ISO Board, as a condition for the owners to join the ISO? Should the ISO have the authority to modify transmission tariffs and operating rules without seeking the approval of the transmission owners? Should the Commission require more specificity on the division of liability between the transmission owners and the ISO? If the Commission is satisfied that an ISO’s governance arrangements ensure independence (i.e., are neutral relative to the economic interests of different classes of market participants and to different states), should the Commission give more deference to the decisions made by the ISO governing board? The experience in other countries suggests that ISOs need to make many adjustments in their early stages of development. The ability of ISOs to make necessary changes in their rules may be slowed down if the Commission employs the same review processes that have historically been applied to the rate filings of traditional vertically integrated public utilities and to power pools with governance structures dominated by transmission owners. Are there streamlined or light-handed regulatory processes that would allow independently governed ISOs to make needed rule changes while still ensuring that the Commission can function as a “backstop” to protect the public interest?

The relationship between an ISO and any power exchange (PX) is also an important issue to consider pertaining to ISO formation. The relationship between an ISO and PX can take on different forms: in California, the ISO will be the control area operator and the PX mandated by State restructuring legislation will be operated independently of the ISO as one of several possible exchanges; in PJM, the ISO operates the PX; and the Midwest ISO does not propose to be either a control area operator or to administer any centralized power exchange. Do the operational features of power systems require that the ISO and PX be one and the same in order for the marketplace to operate efficiently, or can efficiencies be maximized if such institutions operate independently? Should we require that an ISO be associated with a PX? If so, under what conditions?


Panel 3 Role of States

Panel 4 ISOs and Reliability

One purpose of an ISO that is a control area operator is to make an independent party, the ISO, responsible for at least short-term reliability. Increased competition in wholesale electricity markets has resulted in many new market participants, and has fostered a great increase in the number and variety of wholesale transmission and power sale arrangements, including ancillary services needed to accomplish transmission service. As the number of power sales continues to increase, the Nation’s high voltage transmission system is being used more extensively and in ways that differ from its original design. Recent experience indicates that line loading is increasingly problematic. As usage grows, it is increasingly important for regional stability that transmission providers have access to greater information in order to maintain the reliability of the grid.

The Commission is committed to ensuring that the rules and practices for reliable operation of the grid are compatible with open, non-discriminatory use of transmission systems. Regional ISOs would be aware of power flows over a broader geographic region and would be independent of the competitive pressures affecting market participants engaged in power sales and purchases. Are there opportunities for regional ISOs to address reliability concerns and thereby maintain, and even enhance, the reliability of the transmission grid in an open access environment? Should an ISO have a special relationship with regional reliability authorities or should it establish its own mandatory reliability rules? If so, should the rules be determined on a regional or national basis? What is necessary to ensure that regional ISOs will have access to all information required for them to determine power flows in their region? Should the ISO be responsible for both calculating and posting regional ATC values, along with the method and data used to determine these values? Should the ISO be allowed to implement voluntary redispatching of resources for transmission loading relief, before pro-rata curtailment? Would a regional ISO, as compared to an individual transmission owner, be able to manage congested interfaces and loop flow issues in a more efficient and non-discriminatory manner?

The North American Electric Reliability Council has encouraged the development of security coordinators. What rules should apply so that the ISOs’ responsibilities for maintaining reliability appropriately complement utilities’ obligations to maintain reliability at the retail level? Would it be preferable for the ISO to be the security coordinator in its region?

Would other entities through entrepreneurial efforts provide better reliability?

Panel 5 ISOs and Transmission Pricing
Regional ISOs can serve as a vehicle for making transmission pricing more efficient and thereby promote competition in electric markets. Pancaked transmission rates are a barrier to efficient trading because they add an embedded cost charge every time a transaction crosses a corporate boundary. A non-pancaked rate gives buyers and sellers of electricity greater access over a broader geographic market and thereby can remove one of the greatest barriers to trade. Further, regional ISOs may be able to take account of loop flows and price transmission congestion efficiently. Should the Commission establish a uniform method for transmission pricing in regional ISOs, or should transmission pricing be considered on a region-by-region basis? Is it more appropriate for a customer to pay an access charge based on the costs of the transmission owner where the load is located? Or, should the Commission require that access charges be set using a single, uniform rate? Should the Commission consider providing for incentive rates of return to the ISO or transmission owners? If so, how should such incentives be structured? Should they be designed to maximize throughput on the grid or more general measures of efficiency? Should the Commission encourage a uniform model for pricing transmission congestion? Could other transmission entities provide adequate pricing alternatives?

Panel 6 ISOs and Market Monitoring

An ISO is a regulated public utility. However, it is not a traditional public utility because it is typically a non-profit organization that provides services to all market participants and is not directly controlled by any single participant or class of participants. Because the ISO will be involved in the day-to- day operation of the grid, it will know more about the grid and perhaps market operations than any other regional organization. While the Commission cannot abdicate its responsibilities to ensure just and reasonable rates and non-discriminatory terms and conditions of jurisdictional services, ISOs have the potential to monitor the competitiveness of regional bulk power markets and assess the availability of non-discriminatory access to transmission and ancillary services. In orders issued in the California and PJM restructuring proceedings, the Commission (3) required the ISOs to develop market monitoring plans.
(3) See Pacific Gas and Electric Company, et al., 77 FERC 61,265 at 62,087 (1996); Pacific Gas and Electric Company, et al., 81 FERC 61,122 at 61,548-54 (1997); Pennsylvania-New Jersey-Maryland Interconnection, et al., 81 FERC 61,257 at 62,282 (1997).

As explained in PJM, a market monitoring function must be conducted in an independent and objective manner. Should the Commission require every ISO to have a market monitoring plan? Should a market monitoring plan allow the ISO to detect and report market power abuses (vertical and horizontal), assess undue discrimination in the provision of transmission and ancillary services, and assure compliance with the ISO’s rules? Would it be appropriate to include enforcement mechanisms (e.g., sanctions and mitigation actions) with a monitoring function? Must the Commission review any ISO-imposed sanction or would it be appropriate to act only upon complaint? Are there any limitations on the Commission’s authority to permit initial market monitoring to be conducted by ISOs? Should the Commission rely in the first instance on the ISO to monitor discriminatory behavior?

Is it necessary and feasible for ISOs to monitor bilateral markets? Are the potential remedies available to ISOs (e.g., price caps, bidding caps, loss of bidding privileges) likely to be effective if the underlying problem is structural? Should there be different market monitoring requirements for ISOs that do not operate centralized energy markets?

Panel 7 ISOs and FERC Regulation

In Order Nos. 888 and 888-A, the Commission elected not to mandate the formation of ISOs. We stated, however, that if it becomes apparent that functional unbundling is inadequate or unworkable in assuring non-discriminatory open access transmission, we would reevaluate our position and decide whether other mechanisms, such as ISOs, should be required. In Order No. 888-A, we recognized that it would be appropriate to allow some time to confirm whether the functional unbundling mandated by Order Nos. 888 and 889 will remedy undue discrimination before reconsidering our decision that ISO formation should be (4) voluntary. Given that the industry has now operated under the Order No. 888 open access regime for almost two years, the question now before us is whether we should go beyond our current policy of merely encouraging regional ISOs.

(4) Order No. 888-A at 30,249.

The Commission would also like to consider the related issue of whether all public utilities in a region should be required to participate in an ISO when an ISO proposal is geographically fractured. Should the Commission be concerned if some public utility transmission owners in a region refuse to join the ISO? Will a patchwork ISO within a region raise issues of undue discrimination? What should the Commission’s response be to a proposal that has so many geographic holes that it does not permit effective regional competition and may hinder assurance of reliability? Should the Commission define appropriate geographic boundaries for ISOs?

Should the Commission require membership in an ISO in order to remedy undue discrimination under Sections 205 and 206 of the Federal Power Act (FPA)? Would our authority to remedy undue discrimination be broader if an ISO proposal is geographically incomplete (e.g., if similarly situated customers were paying different transmission service rates — one pancaked and one not)? What is the Commission’s authority in these matters over transmitting utilities that are not public utilities?

The Commission has strongly encouraged merger applicants to join an appropriate ISO. Would it be appropriate for the Commission to generically find that a merger applicant’s participation in an appropriately structured ISO is necessary to find that a merger of jurisdictional facilities is consistent 5 with the public interest under FPA Section 203? Should the Commission continue considering whether ISO membership is necessary in individual merger proceedings?

FPA Section 202(a) provides that “the Commission is empowered and directed to divide the country into regional districts for the voluntary interconnection and coordination of facilities for the generation, transmission, and sale of electric energy.” This authority currently resides with the Department of Energy (DOE). If DOE were to use its authority, or delegate that authority to the Commission, should Section 202(a) be used to enhance the development of ISOs in a rational, comprehensive manner? Would Section 202(a) empower DOE or the Commission to define appropriate geographic boundaries for ISOs?

NERC Reliability Workshops

Announcement of Public Workshops on the NERC Electric Reliability Panel Report

The North American Electric Reliability Council (NERC) is sponsoring two public workshops on the report of the Electric Reliability Panel – RELIABLE POWER: Renewing the North American Electric Reliability Oversight System. These one-day facilitated workshops are designed to explain the panel’s report and solicit comments to help NERC develop specific policy recommendations and implementation plans for redesigning NERC.

Workshop Dates and Locations:
February 17, 1998 – 9 a.m.-4 p.m.
South San Francisco Conference Center
255 South Airport Boulevard South San Francisco, California 94080
Tel: 650-877-8787

February 19, 1998 – 9 a.m.-4 p.m.
N.W. Washington, D.C. 20001
Tel: 202-789-1600

In August 1997, NERC assembled the Electric Reliability Panel to recommend the best ways to establish, oversee, and implement policies and standards to ensure the continued reliability of North America’s interconnected bulk electric systems in a competitive and restructured electric industry. NERC imposed no limits on the panel’s advice about what kind of reliability organization will be needed for the future. The panel submitted its report to NERC on December 22, 1997.

Workshop Objectives
NERC is holding these workshops to help its Future of NERC Review Team develop specific policy recommendations and implementation plans. The objectives of the workshops are: * Explain the panel’s report and answer questions. * Hear arguments for or against particular recommendations in the report. * Receive suggestions for implementing the report’s recommendations.

Public Comment Process
NERC has posted the final report of the panel on the Internet ( ~blue/index.html) and is providing 60 days for comments (through March 10, 1998). The questions the review team would like parties to address in their responses are attached to the Notice of Public Comment, which is also posted on the web. All comments will be accepted but must be supplied electronically. NERC will then post all comments it receives on its web site.

What’s Next
Based on comments from these workshops and comments posted on the NERC web site, the review team, assisted by several task groups that it creates, will draft policy recommendations for the NERC Board of Trustees. These recommendations will form the basis for a detailed implementation plan. The draft policy recommendations will be the subject of two additional one-day workshops, tentatively scheduled for March 30 (Dallas) and April 2 (Toronto). The review team will submit final policy recommendations to the Board for review and approval at the Board’s May 4-5, 1998 meeting.

Who Should Attend
Senior management personnel from all segments of the electric industry in North America plus federal, state, and provincial regulators and policy makers are encouraged to attend one of the workshops.

The workshops are open to the public. Dress code is CASUAL.

Preliminary Workshop Agenda 8 a.m. Registration and Coffee

9 a.m. Workshop Convenes Plenary Session * Introductions * Workshop objectives and process * NERC action plan and timetable to address the panel’s report * Background of Electric Reliability Panel study * Panel report and recommendations* Q&A

Breakout Sessions (working lunch included) * Discuss the panel’s recommendations in small, facilitated breakout groups * Develop consensus opinions and suggestions to present to the plenary session

Plenary Session * Reports from breakout groups * Q&A* Summary of agreements and actions

4 p.m. Adjourn

North American Electric Reliability Council (NERC)
116-390 Village Blvd. Princeton , NJ 08540 USA
Main Phone: 609 452 8060 Main Fax: 609 452 9550

Regional reliability councils composed of electric utility systems concerned with the reliability of bulk electric power supply in North America. Organizations comprising the council include in their membership utility systems operating virtually all of the generating and transmitting facilities in 48 American states, the seven bordering provinces of Canada, and a portion of the Mexican power system which is interconnected with that of California. NERC periodically reviews regional and inter-regional reliability and acts as a means for exchange of information on planning and operating matters relating to reliability and adequacy of bulk power supply. Maintains numerous technical subcommittees.

DOE Reliability TF PAPER

Just received from Paul Carrier, Task Force Staff Director:

Attached is a copy of the Paper on “Maintaining Bulk-Power Reliability Through Use of a Self-Regulating Reliability Organization” approved by the Secretary’s Task Force on Electric System Reliability at it November 6 meeting. Also attached is a letter from Dr. Philip Sharp, Task Force Chairman, transmitting the Paper to the Chair of the Secretary of Energy Advisory Board.

(Also available in Word format on request)

Dr. Walter Massey
Chairman, Secretary of Energy Advisory Board
c/o Morehouse College
830 Westview Drive, S.W.
Atlanta Georgia 30314

Dear Dr. Massey:

The Task Force on Electric System Reliability of the Secretary of Energy Advisory Board is writing to provide you with our Task Force Paper entitled Maintaining Bulk-Power Reliability Through Use of a Self-Regulating Organization. This Paper was approved by the Task Force members at our November 6, 1997 meeting.

This Paper expands on the recommendation in our earlier Interim Report that federal legislation clarify the Federal Energy Regulatory Commission’s authority to approve and oversee the operations of a private standard-setting, electric-reliability organization.

The Task Force anticipates preparing additional papers on a variety of electric-reliability topics over the next nine months, leading to a final report.

The Task Force appreciates the opportunity to provide the Department with this Paper and respectfully submits the recommendations therein.


Dr. Philip Sharp
Task Force on Electric System Reliability


cc: Federico Peña
Elizabeth Moler
Secretary of Energy Advisory Board
Task Force on Electric-System Reliability


November 6, 1997

In its Interim Report, the Task Force recommended that federal legislation clarify the Federal Energy Regulatory Commission’s (FERC) authority to approve and oversee the operations of an electric-reliability organization. This paper provides Task Force recommendations concerning the relationship between the FERC and a single, international, self-regulating reliability organization (SRRO) , such as a significantly reformed North American Electric Reliability Council (NERC) with a representative membership and governance system, to assure reliability of the bulk-power system.


Historically, NERC, the regional reliability councils, and individual utilities have managed reliability through a system of peer-reviewed standards coupled with voluntary cooperation and adherence to reliability rules. In that system, costs associated with maintaining reliability could be recovered through rates, and peer pressure and reciprocal treatment of costs were generally sufficient to keep utilities in compliance. Also, NERC, as an international organization, includes members from all countries sharing use of the interconnected transmission grid. Under this system, a set of effective reliability rules was developed and implemented.

The Task Force believes the system is clearly unsustainable in the increasingly decentralized and competitive U.S. electricity industry. Voluntary cooperation is unlikely to be sufficient because of the dramatic increase in the number of bulk-power transactions, the increased diversity of interests among participants, the growing unbundling (deintegration) of the electricity industry, the focus on price, and the lack of appropriate incentives for those entities contributing to reliability.

Most participants in and observers of the electricity industry agree that the voluntary system must be replaced with one that requires compliance with enforceable, non-discriminatory reliability rules applicable to all entities participating in the electricity market. This requires federal legislative authority.

NERC’s Board of Trustees agreed in principle in January 1997 to require adherence to NERC rules and procedures. This new system attempts to feature: measurable performance standards, the requirement that all participants in bulk-power systems meet these standards, enforcement of these standards, and penalties for failure to comply with these standards. The detailed refinement of the standards and implementation of these principles is a work in progress.

Questions remain whether NERC has the authority to require industry participants to abide by the new rules and procedures in the absence of legislation. It is not clear whether the FERC has sufficient statutory authority to enforce NERC rules. The FERC has issued several orders requiring parties to abide by the NERC standards and parties have assented to the requirements. However, the use of FERC’s conditioning authority to enforce NERC standards has not yet been challenged. Others question whether the FERC should enforce these rules in light of concerns over NERC’s governance and decision-making procedures.

In response to these concerns, the Task Force suggests that the U.S. Congress adopt legislation to clarify such authorities and enable the FERC to approve a national self-regulating organization to establish electric reliability standards similar to the National Association of Security Dealers (NASD) in the securities industry. Under federal law, the Securities and Exchange Commission (SEC) has authority to delegate significant regulatory authority to a number of private, member-owned and operated organizations in the securities industry. The SEC has authorized several self regulating organizations (SROs) under the statutory framework.

The experience in the securities industry has been relatively successful in this regard. Self regulation under a legal framework established by Congress, and administered and enforced by a duly appointed federal agency, has certain advantages over government regulation in terms of lower costs to the taxpayer, administrative efficiency and technical expertise in developing and enforcing technical standards, and greater compliance by the regulated firms (because they helped develop the regulations). On the other hand, without careful oversight from the government, SROs might not fully consider the perspectives of the general public and focus too narrowly on the interests of the industry being regulated, especially on issues that involve policy elements rather than technical issues.

SROs have been challenged in the courts and have been found to be legal, but only if properly structured. For example, the SEC Act was found to be a constitutional delegation because:
– The SEC has the power, according to reasonably fixed statutory standards, to approve or disapprove rules; and
– The SEC must make an independent decision on violations and penalties.


Federal legislation should grant more explicit statutory authority to the FERC to approve and oversee an electric industry SRRO having responsibility for bulk-power reliability standards.

As the industry organization currently responsible for electric reliability, most of the members of the Task Force believe that the NERC and its regional reliability councils will evolve into an entity that could fill the role of the SRRO. Most believe the NERC has already initiated many of the changes that will be required for it to be the SRRO. However, we note that this will not occur automatically. In order to qualify as the SRRO, a reformed NERC will have to meet all of the requirements of legislation and the FERC with respect to governance and processes.

The SRRO would provide the technical expertise on how best to maintain high levels of bulk-power reliability. The FERC would have regulatory oversight to ensure compliance with and ultimately resolve disputes over any SRRO mandatory reliability standards. The SRRO would produce mandatory standards applicable to all participants in the domestic and international bulk-power system. The FERC would either confirm SRRO mandatory standards or deny them and refer them back to the SRRO with comments requesting revision and resubmittal of the standards.

The SRRO would develop measurable performance standards. These mandatory standards would replace the voluntary requirements that NERC has previously relied on. Importantly, however, NERC must expedite the development and implementation of measurable standards in an open process that includes full and fair representation of all stakeholders and market participants. The Task Force recognizes that many non-utility participants have significant concerns about membership and representation and believe that NERC and the regional reliability councils must immediately open their membership to balanced representation of all stakeholders and market participants.

Legislation should provide for the following:
FERC review and approval of a proposal for an electric industry SRRO;
FERC implementation of mandatory reliability standards for the nation through rulemakings in accordance with the Administrative Procedures Act;
FERC jurisdiction for reliability over the bulk-power system including those portions owned or operated by federal, cooperative, and municipal utilities and all other entities participating in the electricity market;
FERC review and approval of all SRRO mandatory standards including specified incentives and penalties for compliance;
FERC ability to require the SRRO to develop, modify, or replace standards when necessary;
Mandatory application of reliability standards to all entities using or operating the bulk-power system;
SRRO enforcement of mandatory standards, including imposition of penalties or fines, subject to FERC review;
FERC authority to expedite or temporarily waive procedures when necessary to address an ongoing or imminent reliability problem;
When requested by the SRRO or on its own initiative (e.g., in an emergency situation or stemming from a complaint), FERC review of any SRRO governance or process issues, standards, or SRRO enforcement action; and
Sufficient resources for the FERC to administer its new responsibilities including the authority to levy necessary fees on the industry and access industry computer models, data and transmission experts.

When considering an application for the SRRO, the FERC would give notice of the application and provide an opportunity for public comment in accordance with the Administrative Procedures Act. Particular consideration would be given to SRRO governance, processes, and funding. The SRRO must assure a fair governance process that cannot be dominated by any single industry sector. The FERC would review the application to ensure that the SRRO would function in a manner consistent with the public interest and national reliability policy.

Likewise, when reviewing SRRO mandatory reliability standards, the FERC would issue a notice of proposed rulemaking based on the standard and provide an opportunity for public comment. FERC approval of a standard would require a finding that the standard was fairly developed, is cost effective, and is consistent with the public interest and national reliability policy.

In recognition of the international nature of the interconnected transmission grid, the Task Force has taken the position that mandatory electric reliability standards must be developed by the SRRO and approved by the FERC in accordance with the Administrative Procedures Act. Standard development needs to be done by a single entity that can represent all countries using the interconnected transmission grid. Also, SRRO development of the mandatory standards would avoid the imposition of federally developed standards on those portions of the interconnected transmission grid located in Canada and Mexico. Currently, the Canadian government and electric industry is represented in NERC and it will be necessary to include both Canadian and Mexican representation in the SRRO. The interests of the United States would be protected by enabling the FERC to require the SRRO to develop or modify standards as necessary. It would be incumbent upon the SRRO to develop mandatory standards that are acceptable to all three countries.

DOE Electric Reliability TF-2nd Meeting Minutes

Subject: UFTO Note – DOE Electric Reliability TF-2nd Meeting Minutes
Date: Mon, 19 May 1997
From: Ed Beardsworth

| ** UFTO ** Edward Beardsworth ** Consultant
| 951 Lincoln Ave. tel 415-328-5670
| Palo Alto CA 94301-3041 fax 415-328-5675

DOE SEAB Electric Reliability Task Force-2nd Meeting Minutes

According to our contacts at DOE, the second meeting went well. The group is starting to close on some basic assumptions regarding the future of the electric power industry and on a set of basic concepts/requirements for electric system reliability. In addition, the Task Force is gaining a better understanding of the differing viewpoints of NERC, Power Marketers, and DOE on how to maintain and assure reliability.

The complete minutes are posted at

Secretary of Energy Advisory Board
Task Force on Electric System Reliability

Minutes of Second Task Force Meeting March 25, 1997
Madison Hotel, Washington, D.C.

1.0 Opening Remarks and Perspectives

The second meeting of the Secretary’s Task Force on Electric System Reliability was held on March 25, 1997, in the Madison Hotel, Washington, D.C. Chairman Sharp opened the meeting at 8 a.m., noted that several new members had been added since the first meeting, and introduced those members. Following the introductions, Chairman Sharp stressed his receptiveness to advice from members at any time on how best to handle the agenda and schedule to make the best use of time. He stated his intent to try to get general consensus on a number of issues but stressed that at most some tentative conclusions might be reached at this meeting. He assured the members that they would have other opportunities to consider both the statement of the issues and the consensus Task Force position on each. He encouraged members to speak up and register their thoughts and concerns as the meeting proceeded.

Robert Hanfling, Chairman, Secretary of Energy Advisory Board (SEAB), was introduced by Chairman Sharp and welcomed the Task Force members on behalf of the SEAB and Secretary of Energy, Federico Peña.

2.0 Discussion of Assumptions Regarding the Future of the Electricity Industry

The Chairman thanked Dr. Theresa A. Flaim for her paper about how the electric industry is likely to evolve which proposed a division of assumptions into; A) those on which there may be emerging consensus; and, B) others. He asked that she lead the discussion of assumptions on which there may already be consensus among members. The Task Force opted to add several assumptions, including the one listed first, to better indicate its sense of priorities. There was preliminary consensus on each of the following assumptions:

Assumption #1: The reliability of the bulk electric power system will be maintained.
Comment: The reliability of the bulk electric power system must be a paramount objective in the transition to and maintenance of a competitive market. It was agreed among the members that introduction of competition should not be allowed to negatively impact the reliability of the nation’s integrated bulk electric power system.

Assumption #2: Retail customers will have their choice of supplier.
Comment: Retail customers in many states will also have the right not to choose (i.e., retain service from their existing supplier with a presumption that supplier would remain a provider of last resort).

Assumption #3: Generation can and likely will be deregulated as to price.
Comment: Although market power and transition costs were considered likely to be difficult issues, they were believed not to be closely linked to reliability.

Assumption #4: Transmission and distribution will remain regulated.
Comment: Some ancillary services may be purchased competitively on the open market.

Assumption #5: Power marketers, brokers and commodity retailers will have significant roles.
Comment: None.

Assumption #6: A reliable system will require a Regional Independent Operator (RIO).
Comment: The Task Force noted its unwillingness to use the term “ISO” because it is presently used in widely differing ways by other parties and to avoid appearing to support a particular type of institution at this time.

Assumption #7: The RIO will be a monopoly function and, thus, will need to be regulated.
Comment: This would not preclude a competitive process for acquiring RIO services or for outsourcing by the RIO for specific functions to for-profit contractors.

Assumption #8: Traditional obligation-to-serve compacts will be replaced by obligation-to- connect compacts.
Comment: None.

Assumption #9: RIO’s must not have a commercial interest in the market.
Comment: The security function must be separated completely from commercial operation of the market to avoid conflict of interest.

Assumption #10: RIOs must be able to direct and re-dispatch all generators and customers during emergencies.
Comment: However, RIOs would not necessarily need to have direct control of generation.

Assumption #11: The reliability of the bulk electric power system must be compatible with a range of reliability options for individual customers.
Comment: Customer end-use reliability should be conceptually distinguished from bulk electric power system reliability.

3.0 DOE Paper on Electric Systems Reliability Concepts

The Chairman moved to a discussion of a DOE staff paper intended to promote a better understanding of reliability by identifying basic system concepts and actions required for its attainment/maintenance. The members discussed the primary points made in the paper and reached general agreement on the following concepts:

Concept #1: Characteristics of Electric Systems
General Agreements: The Task Force generally agreed with the staff paper position as follows:

• The bulk power system needs continuous and near instantaneous balancing of generation and load.

• The transmission network is primarily passive but is becoming more active in time..e.g., FACTS.

• Any action can affect many other activities on the grid. — The activities of all players must be coordinated. However, all actions are not equally important.

• Cascading outages are unacceptable. — The physical system and the rules for its operation must minimize the likelihood of such outages.

• The need to be ready for the next credible contingency dominates the design and operation of the bulk power system.

Concept #2: Historical Design Criteria
General Agreements: The Task Force generally agreed with the staff paper position as follows:
• Generation & Transmission Adequacy — Capacity needed to maintain reliability is usually based on probabilistic analyses intended to meet a loss-of-load probability of one day in ten years.

• Generation & Transmission Security — Capacity needed to maintain reliability is based on
N-1 contingency.

Concept #3: Seven Critical Activities for A Reliable Power System
General Agreements: For the purposes of this discussion, the Task Force defined the term ‘system’ to include loads, transmission, distribution and generation and expanded the list of critical activities suggested in the DOE staff paper from five to seven. The additions are distinguished by an asterisk (*).

• Observe the network.
• Analyze and model the system.
• Communicate with operators of other systems.*
• Take control actions.
• Monitor and enforce compliance.
• Plan to expand and/or modify the system (including load management).
• Ensure incentive system for reliability.*

Concept #4: Time Scales for Reliability Maintenance.
General Agreements: The DOE staff paper pointed out that actions required to maintain system reliability take place in very different time frames, from cycles to minutes, to day ahead, to week ahead, to annual maintenance scheduling, and to several years ahead for transmission and generation planning. Each activity and its relative time frame is indicated in Table 1, shown at the end of this document.

Concept #5: Potential Restructuring Impacts
General Agreements: The Task Force generally agreed with the staff paper position that restructuring is likely to affect activities in different time frames, as follows:

• Automatic Protection — No effect
• Disturbance Response — Must consider contractual obligations
• Regulation and Voltage Control — Competitive markets will replace centralized control in selecting resources
• Economic Dispatch — Selecting units based on markets need not affect reliability
• Maintenance Scheduling — Scheduling of transmission maintenance should be under the authority of the Regional Independent Operator
• Fuel Planning — No effect
• Transmission Planning — If congestion rents can be captured, reliability constraints will be relieved. If not, there will be little incentive to take actions to relieve constraints.
• Generation Planning — Reliability will be maintained during the transition from central planning to the marketplace.
4.0 Panel Discussion and Roundtable on Policy and Institutional Issues

The Chairman moved to the next item on the agenda and introduced each of three panelists representing different perspectives on reliability and restructuring: Marc W. Chupka, DOE Acting Assistant Secretary for Policy and International Affairs; David R. Nevius, Vice President of the North American Electric Reliability Council (NERC); and, Barry N. P. Huddleston, Regional Manager, Regulatory Affairs, Destec Energy Corp. The Chairman pointed out that the panelists’ positions on each of the seven policy and institutional issues scheduled for discussion were documented in the meeting material and that, consequently, he would ask them to provide only brief introductions and then join in the Task Force roundtable discussion of each issue.

After a brief introduction by each panelist, the Chairman opened the discussion of the issues presented in the meeting material. While it is premature to consider any of the comments shown below as a conclusion or consensus by the Task Force, the following reflects some of the more notable opinions relative to each issue discussed.

Issue #1: Who should define and measure bulk power system reliability?
• Reliability standards should not be legislated.
• The institutions setting reliability standards must be separated from those responsible for measurement or enforcement.
• The composition of the institutions setting reliability standards should reflect that of the restructured industry (including customers).
• Setting and enforcing reliability standards probably will require a regulatory backstop.
• Relationships established by legislation and contracts will need to be well understood (e.g., who has enforcement responsibility? who has an appellate function?).
• In the future, reliability will need to be defined in terms of customer perspectives but customers will not be able to purchase higher reliability than is designed into the bulk electric system unless they are willing to acquire localized resources for themselves.
• Approved tariffs of the future will be required to specify the applicable standards and the consequences that will apply if they are not met.
• Compacts among states to address reliability issues may alleviate the need for intervention by the federal government at the time of an emergency.
• States certainly will want to continue to be involved to protect their constituents.
• Additional federal authority may be needed to resolve all the compliance matters.
• NEPOOL depends on regulatory agencies in six states that have a history of long standing coordination and cooperation, but they rely on FERC regulation for backstop.
• FERC only exercises jurisdiction over 60-70% of the power system. The system also involves Canada and Mexico — clearly not under FERC jurisdiction. Legislation, or the threat of legislation, will be needed.
• A broad based organization (like NERC) is the best option to define standards regarding the security of the bulk electric power system. However, the marketplace should decide on matters of adequacy.
• A region like New England that decides to join together and operate in a unified system may not need federal authority except on issues that may affect the Regional boundaries.
• Legislation may be required to clarify federal authorities, as opposed to expanding them.

The Chairman concluded this portion of the discussion and opened the floor to comments by members of the public.

5.0 Public Comment Period.

The Chair recognized Mr. Mark Lively who indicated his concerns about how the industry will function in a deregulated environment, particularly in terms of two sciences, physics and economics. He referred to NERC’s interests as those representing the science of physics and FERC’s interests the science of economics. He stressed a need to consider them jointly and to be very precise in the definitions used in the process (e.g., utilities have not had an obligation to serve, they have had an obligation to serve at a price). He questioned whether transmission needs to remain a natural monopoly.

The Chair next recognized Mr. Jose Calvo of the Nuclear Regulatory Commission (NRC). Mr. Calvo stressed the need to set reliability standards before problems arise…not afterwards. He indicated NRC’s interests in the possible effects of restructuring on the availability of off-site power for nuclear plants. He noted that additional on-site backup power sources may be needed at nuclear plants if backup supplies from the grid cannot be assured at all times.
6.0 Panel Discussion and Roundtable (Cont’d)

Following comments by the public, the Chairman resumed discussion of the seven issues presented in the meeting material. Again, while it is premature to consider any of the comments shown below as a conclusion or consensus by the Task Force, the following reflects some of the more notable opinions relative to each issue discussed.

Issue #2: Should a minimum capacity requirement, or reserve margin, be established for all load-serving entities?
• The Regional Independent Operator should assure that the necessary minimum reserve is available.
• If capacity reserves can be procured in the market, let the market supply them.
• The system can be operated reliably with insufficient reserves…those customers with reserves could continue to be served while those without would have service terminated.
• Customers that want to pay for 15% capacity overhang should be able to buy it — those that want 30% capacity overhang should be able to buy that — but to obtain higher reliability than the bulk system is designed for will require that customers acquire local supplies for themselves.
• The need to establish day-ahead minimum capacity requirements is clear. The issue is how far to go into the future — 6 months?–12 months?
• Another key issue is ‘who gets disconnected first?’ Those with reserves will stay connected. It is a matter of defining the rights and incentives (or penalties) of customers.
• Long term prices send signals for the investment community to build capacity and, in addition, customers are going to have contracts. The contracts will specify how much reliability customers want.
• Bulk system reliability has the characteristics of a “public good.” That is, everyone wants it. If it is obtained, everyone enjoys it whether they paid their share of its costs or not. Consequently, everyone has an incentive to avoid paying for it — which puts the good at risk.
• A basic problem: How to manage unpredictable loads while minimizing the need for installed capacity? Edicts by fiat on how much reserve capacity is needed for reliability are likely to be incorrect by a significant margin. The solution is to let the market resolve these balancing problems whenever possible.
• Legislation may be required to clarify federal authorities, as opposed to expanding them.

Issue #3: What is the appropriate use of engineering standards and markets to ensure adequate ancillary services?
• The overall presumption of this committee should be biased toward letting the market provide ancillary services …if it can. If it can’t, the Regional Independent Operator takes over. Market rules should be relied on to the maximum extent. A basic problem: Where’s the boundary? Who determines it?
• Make Regional Independent Operators responsible for providing the services but allow self-provision of ancillary services by suppliers and customers as an option.
• Let individual buyers and sellers work out their own arrangements…but assure that the Regional Independent Operator takes over in default.
• Line loading relief and re-dispatch should be a Regional Independent Operator function.

Issue #4: Who should be responsible for transmission planning, construction and maintenance?
• The issue is not who can build…but who has the capacity to collect from customers, so as to cover the costs of construction? Only a regulatory entity has the right to site.
• A regional focus for planning is essential.
• Transmission expansion does not present premium investment opportunities. There does not appear to be any way to avoid taking a regulated approach, with investment going into a rate base.
• The core issue seems to be who should be doing studies to determine whether new transmission is needed and, if so, where.
• Studies done in the 1980s on transmission siting by NGA and Keystone should be reviewed.

Issue #5: What authorities or incentives are needed to ensure that system operators will be able to compel real time actions by users of the bulk power system, when necessary, to maintain reliability?
• Additional regulatory authorities are not needed. It should be possible to design and utilize contract provisions that are capable of ensuring proper behavior by users of the bulk power system.
• Penalty-backed financial decisions could be used to force customers off the system when necessary. After-the-fact assessments of very high costs for service (e.g. $90,000/kWh) are likely to be effective.
• We need an objective, duly appointed body to say what is fair and what the standard (penalty) should be. Probably FERC.
• After-the-fact penalty assessments will assure that someone pays, but in real time someone will have already paid for whatever extra capacity is available, and that margin gives others the opportunity to “lean” on the system. We need to be careful that this sort of opportunistic behavior does not erode the system’s resilience.

Issue #6: What legal recourse should customers, other market participants, or the public have if reliability is not maintained?
• The court system permits utilities, RIOs , etc. to be sued. These entities will have to carry insurance…for which users will have to pay…somehow.
• A FERC-backed stiff penalty ($90,000/kWh) may be the answer.
• Penalties are preferable to extensive reliance on court proceedings.
• Litigation has not been effective in the Northwest.

Issue #7: What is the appropriate role for government in ensuring electric system reliability?
• FERC may be the right agency to handle oversight responsibilities, but are they equipped to handle the additional mission?
• FERC could delegate oversight responsibilities to NERC.
• Bulk power should be a federal oversight responsibility. Local reliability should be a state function.
• An industry compact could cover all sectors that are now regulated by FERC plus some areas (Canada, Mexico) that are non-FERC jurisdictional.
• States may need help in dealing with new T&D issues [EPRI has good material on this, e.g., EPRI has a power quality benchmarking capability already].

7.0 Final Public Comment

The Chairman offered a final opportunity for public comment and Mr. Mark Lively was the only commentor. He offered his opinion that, if a very large penalty ($90,000) was adopted for customers leaning on the system in the short term, the long term will take care of itself. Investors will see the opportunity and invest accordingly.

The Chairman closed the meeting by thanking the members for their participation. He advised them that the next meeting would probably be scheduled sometime in late May but would be coordinated with everyone’s schedule, and adjourned the meeting at 4 p.m.

Mr. Rich Burrow, DOE staff representative to the SEAB, suggested that Task Force members use the SEAB Home Page for information pertaining to minutes of meetings, membership, notices of future meetings, reports, etc. He announced that the Internet address of the SEAB Home Page is: http: //
Table 1:
Services Affecting Bulk Power Reliability

Service Time Scale Description
Automatic Protection Instantaneous Minimize damage to equipment and service interruptions
Disturbance Response Instantaneous-minutes-hours Adjust generation, breaker, and other transmission equipment
Regulation & Voltage Control Seconds-minutes Adjust generation to match scheduled intertie flows and actual system load
Economic Dispatch Minutes-hours Adjust committed units to maintain frequency…at minimum cost
Unit Commitment Hour ahead & week ahead Decide when to start up and shut down generating units
Maintenance Scheduling
(Long Term) 1-3 years ahead Schedule and coordinate interutility sales and planned maintenance
Fuel Planning
(Long Term) 1-5 years ahead Develop least cost fuel supplies, contracts and delivery schedules
Transmission Planning
(Long Term) 2-10 years ahead Design regional and local system additions
Generation Planning
(Long Term) 2-5 years ahead Develop mix of new units, retirements, life extensions, and repowering based on long term load forecasts

DOE Electric Reliability TF Meeting Minutes

Subject: UFTO Note – DOE Electric Reliability TF Meeting Minutes
Date: Thu, 27 Feb 1997 09:16:14 -0800
From: Ed Beardsworth

| ** UFTO ** Edward Beardsworth ** Consultant
| 951 Lincoln Ave. tel 415-328-5670
| Palo Alto CA 94301-3041 fax 415-328-5675

Attached are the approved minutes of the first meeting of the Electric System Reliability Task Force. The minutes were approved by Chairman Phil Sharp on February 24, 1997.

The second meeting of the Task Force will be held in Washington DC on March 25th at the Madison Hotel. The meeting will tentatively start at 8:00 AM and last until 4:00 PM.

The meeting will tentatively include:

1) A discussion of “Assumptions Regarding the Future Electricity Industry”, based on a paper by Theresa Flaim entitled “A Vision of the Competitive Electricity Market – What’s Clear, What Isn’t”.

2) A discussion of the “Basic Concepts and Operating Requirements for Electric System Reliability”, based on a staff paper.

3) A discussion of “Policy and Institutional Issues”, where staff from NERC, DOE and a Power Marketer will present their views on how policy and institutional reliability issues should be addressed.

4) Planning and Scheduling of Future Meetings.

A Federal Register Notice will be published at least 2 weeks before the meeting. It will include the agenda and principal speakers.


Secretary of Energy Advisory Board Task Force on Electric System Reliability Minutes of First Task Force Meeting January 16, 1997

J.W. Marriott Hotel Washington, D.C.

1.0 Opening Remarks and Perspectives

The first meeting of the Secretary’s Task Force on Electric System Reliability was held on January 16, 1997, in the J.W. Marriott hotel, Washington, D.C. Robert Hanfling, Chairman, Secretary of Energy Advisory Board (SEAB) opened the meeting at 8:30 am with a brief welcome to the members and an introduction of the Task Force Chairman, Philip Sharp (the Chairman).

The Chairman thanked the members for agreeing to participate on the Task Force and expressed his respect for the work they do in “keeping the lights on.” He recalled the major electrical outages in the West last summer as painful reminders of what happens when the lights do go out. He called attention to the great changes taking place now in the electric power industry (e.g., participants, demands, economic incentives) and stressed that one of the main goals of this Task Force was to make sure that reliability did not get lost in the transition. He then introduced Deputy Secretary of Energy Charles B. Curtis.

Deputy Secretary Curtis thanked the members for interrupting busy schedules and expressed his hope that the work of this panel will be useful for present and future generations. He observed that the industry is irreversibly committed to restructuring and stressed the need to assure that reliability is afforded its proper place for consideration in the evolving change. He commented that with the continued economic growth and development in our country, blackouts are debilitating to our economy and becoming even more so. The Deputy Secretary offered seven specific challenges to the Task Force:

-Although the bulk electric power system has functioned well under a sense of voluntarism, thanks largely to the North American Electric Reliability Council (NERC) and its regional councils, will voluntarism be sufficient to assure reliability under the new paradigm?

-Are federal authorities adequate and are they properly lodged in the right agencies (e.g., DOE, FERC)?

-Given the advances which have taken place in industry technology, operational procedures and training, which permit the system to be operated closer to the margins, are we asking operators to do more than is reliably possible?

-Given the evolving changes in economic incentives which underpin the industry, is the industry likely to continue to invest wisely and adequately in R&D?

-Given that the concept of an independent system operator, in one form or another, is under strong consideration in many states, is that concept necessary and sufficient for maintaining a secure and reliable system?

-Is the balance between federal/state regulations proper, and is it possible that the states could do more to assure reliability?

-Given that the 105th Congress intends to focus sharply on electricity restructuring during this session and that the Administration will likely submit legislation this year, what are the recommendations of this Task Force?

2.0 Task Force Member Introductions

Following these remarks, the Chairman asked each of the 18 present and three telecommunicating members of the Task Force to introduce themselves, briefly describe their background and describe any areas in which they felt their expertise might be especially helpful to the group.

3.0 Institutional Reliability Issues

The Chairman then introduced Mr. Michehl Gent, President, North American Electric Reliability Council (NERC), to discuss institutional reliability issues. Mr. Gent briefly described the three interconnections and noted that the regions, now numbered at ten, initially were formed by the people in each region to address the unique needs of that region. There was no intent then to make them similar since there was no thought of sending power from Minneapolis to Florida. As a result of changes, both those which have taken place already and those anticipated, the regions are becoming more alike in terms of their electric power planning and operations. He recalled events leading to the formation of NERC in 1968 after the northeast blackout of Nov. 9, 1965, and described its three primary objectives; to establish standards, measure performance, and ensure compliance. Of special note, he thought, were actions taken by NERC to adapt to evolving changes in ownership and access. By way of example, he noted that membership on the Board of Trustees had increased to 34 with representation by all segments of the industry, and also that the number of organizations with observer status had increased. Mr. Gent then introduced Don Benjamin, NERC’s Director of Operations, to discuss some of the specific activities underway within the industry to assure reliable operations in the new environment.

Mr. Benjamin highlighted a number of current initiatives, in areas of: operational security; transmission use; operating standards, interconnected operations services; and, actions to address major outages in the West last summer. He concluded with a summary statement of goals for a reliable electric system which can accommodate the marketplace by:

-operators having the “big picture” at all times; -analyzing transactions before they are consummated; -ensuring compliance with NERC policies; -establishing a program of system operator certification; and, -defining requirements for interconnected operations services.

Mr. Benjamin described in some detail NERC’s previous approach to operational security in which interconnected but nearly autonomous systems have operated through about 150 control areas established so as to be able to operate so that problems are contained within the area and do not pass beyond the boundaries. He indicated that goal is becoming more difficult to achieve on a control area basis with the increased role of market entities and open access. To supplement the control centers, the industry is moving toward security coordinators, fewer in number at twenty-two, with responsibilities to perform security analysis based on interchange schedules, coordinate emergency operations (e.g., transmission overload relief, load reductions), manage the interregional security network, and develop operating policies as may be needed. In terms of status, he advised that regional security plans are in place, coordinators exist and will have their first meeting in February, and that necessary databases are known and in preparation.

In response to a question (Cavanagh) of whether the new security system can handle tens of thousands of transactions/hour, Mr. Benjamin noted that: “We’ll have to. We probably can’t today…but we’re closer today than we were 5 years ago. With computer technology…it should be possible. Multi-regional models handle the flows and will be updated continuously. They will be able to reflect, ideally, what is really happening in the system.” Mr. Budhraja stressed the big difference between physical and financial transaction systems noting that the number of generators and points of consumption will not change, while financial transactions can number in the thousands.

The Chairman asked the status of the models NERC uses to monitor security and was informed by Mr. Benjamin that they have existed and been kept current for years. What is not in place yet is the ability of the operators to access those models in real-time. That capability is undergoing development right now. Once real-time access is possible by all operators, they can test a transaction real-time and, if it is feasible, conclude it.

4.0 Technical Reliability Issues

The Chairman then introduced Dr. Karl Stahlkopf, Vice President, Power Delivery, Electric Power Research Institute (EPRI), to discuss technical reliability issues. After a brief review of differences between design objectives for the system and the way it is being operated today, Dr. Stahlkopf moved on to discuss the causes of and lessons from last year’s major outages in the West.

After a brief background review of the record heat and unusual power flows which preceded the August 10 outage, Dr. Stahlkopf described its chronology. He then summarized the basic causes of the outage as follows:

-systems were stressed; -not enough reactive support/control in the area; -initiating conditions not studied before; -operators did not know system was insecure; -no one had the “big picture”; and, -reliability impact of maintenance not understood.

As far as lessons learned, Dr. Stahlkopf said he did not believe restructuring was a factor in the outage; rather, the system simply was stressed due to hot weather. On the other hand, he did believe that financial incentives were a factor (i.e., cheap hydro-power in Northwest); they caused flow patterns which were unusual for that time of year and, coincidently, had not been studied. Regarding lack of reactive support in the Western System Coordinating Council (WSCC) at that time, Dr. Stahlkopf noted ongoing studies by NERC and EPRI aimed at determining whether this is a chronic problem.

On the subject on maintenance impacts on reliability, Dr. Stahlkopf noted that BPA had increased their vegetation maintainance budget because of a wetter and hotter than normal growing season but questioned whether, in a competitive market, financial disincentives would exist to cause utilities to try and limit their expenditures on maintainance. Members of the Task Force agreed that this aspect must be addressed.

Dr. Stahlkopf moved on to a discussion of technology improvements that might help avoid such an occurrence in the future. He mentioned three major improvements as being Flow Actuated Control Thyristors (FACTS), Static Compensator (STATCOM), and Unified Power Flow Controller and summarized the likely contributions to reliability of each. One member of the Task Force (Budhraja) commented that all of these devices contribute to getting more out of the installed system and observed the obvious reliability implications. He questioned whether the industry should also be thinking about adding to transmission systems so they don’t have to be operated so close to their limit.

After brief discussions of the Wide Area Measuring System (WAMS), an operations data system, and several EPRI initiatives targeted on maintenance, Dr. Stahlkopf concluded that near-term technologies may improve reliability in four areas: operating tools; transmission system “agility”; monitoring and communications; and, reducing maintenance costs reliably.

5.0 State Reliability Issues

The subject of state reliability issues was addressed by the Honorable Duncan Kincheloe, Commissioner, Missouri Public Service Commission. Mr. Kincheloe said that, while states have historically engaged in regulating the power industry, can establish standards for voltage regulation, govern service priorities for restoration and curtailment, and can set standards for reserve margins, they now face prospects of diminished success in regulatory actions and need new mechanisms to look at reliability. In this regard, he suggested several areas which may warrant further consideration.

-in the area of generation and supply, he acknowledged that: past assurance of rate-based adjustments (by states) to cover investments in capacity may have undergirded utilities’ willingness to invest; and, whereas local distribution companies had responsibilities to restore service in past emergencies as a consequence of franchised territories, this may no longer apply in a competitive future.

-in the area of Federal regulation, he said: if Congress legislates retail competition, states must have authority to demand evidence of experience at providing service/reliability for new market entrants; and, if Congress legislates a (minimum) reliability standard, states would want the responsibility to assure compliance-according to historical roles- and the authority to tighten the standard, if desired.

He concluded with his opinion that states are very much in the transmission regulation business but have major concerns (with the Federal Energy Regulatory Commission (FERC)) with the issue of jurisdiction over unbundled retail power.

After the lunch break, the Chairman announced his intention to open the floor for public comment, followed by a return to member discussions on Mr. Kincheloe’s presentation.

During the public comment period, one observer rose to discuss the use of direct current on the bulk power system and noted that it is on the increase. His consulting company has been advising customers to “move away from the grid” toward more reliance on direct current and he hoped that the Task Force would consider this evolving trend in the industry.

There being no further comment by the public, the Chairman returned to discussions on Mr. Kincheloe’s presentation. During the discussion that followed, a question was raised (Holden) regarding the status of the federal/state transaction “debate. Mr. Kincheloe answered that FERC has asserted jurisdiction over certain unbundled components which heretofore had been within the purview of the states (e.g., retail transactions involving some component of the transmission system). Under the unbundling, FERC has now asserted jurisdiction.

In another area, a question was raised (Dragoumis) as to whether there have been any attempts to establish state compacts (i.e., agreements between two or more states) to set reliability rules and standards. The Chairman noted that states may propose to Congress the approval of compacts, and Congress usually approves them. The problem is that it is unlikely for states to propose compacts on very complex issues because it is so difficult for them to agree on the details.

One member (Meyer) questioned how states would be likely to handle suppliers who have, say, only one generator and whether they would require 100% reserve. While this was considered unlikely, it was also the case that the state probably wouldn’t want to impose very stringent requirements either because the suppliers would be likely to withdraw from doing business in their state….and that would affect the level of competition.

Another member (Flaim) stressed the likely need for different levels of reliability in different places but acknowledged that state-wide, regional or national reserve margins is a problem.

The experience of four years ago with the shutdown of the District of Columbia, including the Secretary of Energy’s call for industry change to avoid such events in the future for the nation’s capital, was cited by one member (Dragoumis) as an example of an action that easily might have required physical changes to the electric system outside the District. This was posed as a clear question of oversight responsibilities and a need for proper incentives.

6.0 Task Force Work Plan Development

In response to the Chairman’s request for specific suggestions of issues to be considered by the Task Force, the members identified and discussed the following:

-Vikram Budhraja noted that, while the system is comprised of generation, transmission and distribution components, 80-90% of the disruptions take place on distribution systems but 70-90% of the expenses are directed to the transmission system. He said that problems on the interconnected grid are simply unacceptable but acknowledged that those issues involve jurisdictional questions.

-Rich Sedano said he believed that generation may need to be parsed into the ancillary services expected with that generation.

-Earl Nye urged the Task Force not to ignore either distribution or generation but to focus instead on the integrated, interconnected grid. He expressed his belief that the market will provide…over time but that, unfortunately this is an instantaneous business. No one expects 100% reliable power everywhere all the time.

-Jose Delgado noted that there is a definite time dimension to the issue of reliability and questioned whether an ISO will have to balance generation and load…instantaneously. Load management, he thought, will be done as a result of market decisions.

-In response to a question by Mark Bonsall as to whether the ISO will be able to accomplish the load/generation balances, Vikram Budhraja stressed that a system cannot be run without doing that. The real question, he thought, involves both who will pay for the service and the consequences when the ISO does have to take action to balance the system.

-Theresa Flaim questioned whether a scoping document was needed to focus the deliberations, possibly grounded in the physical system, possibly on the basis of time. She felt the need to do a basic scoping before attempting to address issues like “what legislation is needed.” She suggested an initial attempt to define the dimensions of reliability.

-Matthew Holden questioned the group’s assumptions regarding the composition of the electric system 10 or 20 years out. That is, whether we expect to be operating under a new gee-whiz electric system, better but in many ways similar to the present system, or that we don’t know what the system of the future will look like.

-In addition to the components of generation, transmission, and distribution, Jose Delgado advised the group not to lose sight of load and institutional issues as possible factors of reliability.

-Alden Meyer suggested the use of scenario analysis to better frame the issues. He thought it would be extremely helpful to be able to advise policy-makers on the likely consequences to reliability of moves in one direction or another.

-Vikram Budhraja cautioned against the use of structural models (e.g., California, Niagara) citing a fundamental change in paradigms. Under the present system, customers have no choice. In the new environment, customers do have a choice. That is a fundamental and powerful distinction. He thought that producers will have more freedom to enter and leave the marketplace and that the electric grid is a unified network; it does not recognize individual ownership.

There being no further comments by the Task Force, the Chairman briefly summarized the accomplishments of the meeting, thanked the members for their attendance and active participation, and adjourned the meeting.