Competition in the Electric Industry : Emerging Issues, Opportunities, and Risks for Facility Operators [1 ed.] 9780309590044, 9780309056816

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Copyright © 1996. National Academies Press. All rights reserved.

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Competition in the Electric Industry: Emerging Issues, Opportunities, and Risks for Facility Operators Conference Summary

Federal Facilities Council Standing Committee on Operations and Maintenance Report Number 132

NATIONAL ACADEMY PRESS Washington, D.C. 1996

Competition in the Electric Industry : Emerging Issues, Opportunities, and Risks for Facility Operators, National Academies Press,

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ii NOTICE The Federal Facilities Council (FFC) (formerly the Federal Construction Council) is a continuing activity of the Board on Infrastructure and the Constructed Environment (BICE) of the National Research Council (NRC). The purpose of the FFC is to promote continuing cooperation among the sponsoring federal agencies and between the agencies and other elements of the building community in order to advance building science and technology–particularly with regard to the design, construction, and operation of federal facilities. Currently, the following agencies sponsor the FFC: Department of the Air Force, Office of the Civil Engineer Department of the Air Force, Air National Guard Department of the Army, Corps of Engineers Department of Energy, Office of Associate Deputy Secretary of Field Management Department of the Navy, Naval Facilities Engineering Command Department of State, Office of Foreign Buildings Operations Department of Veterans Affairs, Office of Facilities Management Food and Drug Administration General Services Administration, Public Buildings Service Indian Health Service National Aeronautics and Space Administration, Facilities Engineering Division National Institutes of Health National Institute of Standards and Technology, Building and Fire Research Laboratory National Endowment for the Arts, Design Arts Program National Science Foundation Smithsonian Institution, Office of Facilities Services U.S. Information Agency, International Broadcasting Bureau U.S. Public Health Service, Office of Management U.S. Postal Service, Facilities Department As part of its activities, the FFC periodically publishes reports like this one that have been prepared by committees of government employees. Since these committees are not appointed by the NRC, they do not make recommendations, and their reports are considered FFC publications rather than NRC publications. For further information on the FFC program or FFC reports, please write to: Director, Federal Facilities Council, Board on Infrastructure and the Constructed Environment, 2101 Constitution Avenue, N.W., Washington, D.C. 20418.

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FEDERAL FACILITIES COUNCIL STANDING COMMITTEE ON OPERATIONS AND MAINTENANCE Chairman James Walton, U.S. Army Corps of Engineers, Department of the Army Vice Chairman Richard McCrone, Operations and Energy Management Division, Department of Veterans Affairs Members Subrata Banerjee, Bureau of Health Resources Development, U.S. Public Health Service Walter Borys, Network Engineering, International Broadcasting Bureau Hao Bui, Facilities Engineering Branch, International Broadcasting Bureau Jodi Ernst, Office of Facilities Services, Smithsonian Institution Paul Fardig, Engineering Support Services Branch, U.S. Public Health Service Gary Fennell, Facilities Division, Air National Guard Paul Fennewald, Maintenance Branch, U.S. Postal Service Geoffrey Frohnsdorff, Building Materials Division, National Institute of Standards and Technology William Graham, Engineering Management and Field Support Office, Department of Veterans Affairs Benjamin Herrick, Network Support Division, International Broadcasting Bureau John Iaconis, Public Buildings Service, General Services Administration

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William Johnson, Facilities Engineering Branch, Indian Health Service Gregory Krisanda, Office of Foreign Buildings Operations, U.S. Department of State Peter Lastik, Facilities Division, Air National Guard Patrick Miller, Office of Plant Services, Smithsonian Institution William Morrison, Facilities Division, Air National Guard Charles Pittinger, Jr., Facilities Engineering Division, National Aeronautics and Space Administration Douglas Rowand, Facilities Division, Air National Guard Steve Salter, Naval Facilities Engineering Command, Department of the Navy John Scalzi, Structures and Building Systems, National Science Foundation J. Ronald Smith, Division of Facilities Management, Food and Drug Administration, U.S. Public Health Service Gregory Tsukalas, Facilities Branch, U.S. Army Corps of Engineers Nongovernment Liaison Members Dianne Davis, American Public Works Association Robert Hummer, Association for Facilities Engineering Staff Lynda Stanley, Director, Federal Facilities Council Lena Grayson, Project Assistant

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PREFACE

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PREFACE

COMPETITION IN THE ELECTRIC INDUSTRY: EMERGING ISSUES, OPPORTUNITIES AND RISKS FOR FACILIITY OPERATORS Significant and rapid changes are taking place in the electric industry as a result of efforts to introduce competition. The industry is in a period of transition as it moves toward open access transmission and as services such as power generation, transmission, and distribution are "unbundled" and opened to competition. These changes will ultimately effect those who generate, market, and purchase electricity. Reductions in electric power costs is one potential outcome of the effort to introduce competition in the industry. Such reductions would be supportive of the National Construction Goals of the National Science and Technology Council which seek to achieve a 50% reduction in operation, maintenance, and energy costs of facilities by 2003. However, competition for electricity raises a number of significant issues. These include how to establish a clear line of jurisdiction on electric power issues between the Federal Energy Regulatory Commission and the 50 states and the District of Columbia; how to retain the reliability of the system; how utility companies will be reimbursed for past investments in generating facilities, made in good faith, that will become uneconomic in a competitive market (so-called stranded costs or stranded investments); impacts on special purpose programs, such as research and development, demand-side management, energy efficiency programs, and rate assistance to low income households; and potential impacts on consumers. To address these and other issues the Federal Facilities Council convened a conference on "Competition in the Electric Industry: Emerging Issues, Opportunities, and Risks for Federal Facility Operators" in May

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PREFACE

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1996. The conference brought together experts in regulatory policy, energy markets, utility operations, and government procurement, from industry, government, nonprofit research organizations, and academic institutions. The objective was to provide a nontechnical overview of the significant issues and potential impacts of competition in the electric industry on consumers in general and federal facility operators in particular. Speakers focused on: • The background, current status, and future prospects for competition in the electric industry • Jurisdictional issues and relationships between federal and state regulators • Issues of electric power ownership, distribution, services, and pricing • Restructuring of the electric industry and the emergence of new entities in that industry • Federal agencies' perspectives on potential opportunities, risks, procurement, and management considerations for federal facility operators. This report includes papers based on many of the presentations made at the conference. In a few instances, the papers refer to actions taken between the time of the conference (May 1, 1996) and the printing of this report (November 1996), to provide up-to-date information for the reader.

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CONTENTS

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CONTENTS

Executive Summary

1

The Federal Energy Regulatory Commission's Open Access Rule

6

Electric Power Competition: Perspective of a Regulator

13

A Road Map to Electric Restructuring in California: Decisions 95-12-063 and 96-03-022

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The Restructuring of California's Electric Industry: A Utility's Perspective

35

Competition in the Electric Power Industry: A View from New York

44

Buying and Selling Electricity: Perspective of a Power Marketer

53

Perspective of an Electrical Power Customer

58

Opportunities and Risks in Electric Competition: A View from the Department of Defense

62

Competition in the Electric Industry : Emerging Issues, Opportunities, and Risks for Facility Operators, National Academies Press,

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viii

Saving Billions from Energy Efficiency in the Federal Sector: Institutionalizing Energy Efficiency in Facility Management 66

Acquisition of Utilities Services: Some Legal Considerations 72

Additional Considerations in the Electric Competition Debate 76

Speaker Biographies 84

Glossary 87

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EXECUTIVE SUMMARY

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EXECUTIVE SUMMARY

The United States spends about $300 billion annually for electric power; wholesale purchases total about $90 billion and the retail purchases, by the endusers, account for more than $200 billion. For the past 65 years, this industry has been highly regulated as to price. However, efforts are now underway by state and federal regulatory agencies and legislators to introduce competition. These efforts will likely transform the way power is purchased and sold by industry and individual consumers. Factors cited as contributing to the moves toward competition include technology advances leading to lower generating costs; a more competitive global market; the failure of regulation to produce uniform and reasonable electric power rates across the United States (currently, rates range from 14 cents per kilowatt hour on Long Island to 4 cents per kilowatt hour in the Pacific Northwest); and pressure on legislative bodies from consumers and industries to provide relief from high electric power costs, which have been cited as a factor in corporate decisions to relocate factories and jobs from high cost to lower cost areas. In the traditional vertically integrated electric industry structure, generation, transmission, aggregation, and distribution of electricity were all provided by local utilities with exclusive retail service territories. However, the electric transmission system in reality is an integrated interstate network owned by individual, state-regulated utilities. Electric power rates are established and regulated by the Federal Energy Regulatory Commission (FERC) in combination with the 50 states and the District of Columbia. FERC regulates the price of interstate electricity transmission and access to interstate transmission services, and has authority over certain mergers and acquisitions; FERC regulates prices to wholesale users of electricity, not end-users. The 50 states and the District of Columbia, regulate local utilities and set rates for electricity purchased by endusers. There is a widely held view that the generation of electricity can be competitive; that an entity other than a utility company, a so-called independent power producer or nonutility generator, can build a power

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EXECUTIVE SUMMARY

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plant and generate power efficiently. Historically, however, the transmission and distribution of electricity has been considered a natural monopoly: in any region there is only one owner and operator of the wires carrying power to industry and households, and that owner and operator is usually the utility company which also owns substantial power generating assets. Thus, while consumers could, in theory, buy power from nonlocal generators, there was little opportunity to transport or ''wheel" the power to the desired destinations because the utilities were reluctant to grant their competitors access to the transmission and distribution systems. The Energy Policy Act of 1992 opened wholesale generation markets to competition, so that a wholesale buyer may purchase electricity from any generator, not just the local utility. (The Energy Policy Act specifically forbids FERC from ordering retail wheeling.) In April 1996, the Federal Energy Regulatory Commission issued Orders 888 and 889 requiring all public utilities to file tariffs providing nondiscriminatory access to all wholesale users for a defined set of transmission services, by July 1996; adopted comparability standards and functional unbundling to help guard against discrimination; announced procedures for sharing information; and established a schedule for implementation, among other actions. FERC has estimated that this action could save electricity consumers $3-5 billion per year as less expensive regional power becomes available to any customer on the national power grid. While wholesale competition is being implemented, state utility commissions across the nation are moving to establish open retail markets for power consumers in an effort to lower costs and eliminate the wide disparities of cost that now exist within and between states. While it is not clear that the states have the authority to order retail wheeling, and the issue may be decided in the courts, most states are moving ahead with proposals for retail competition. California's plan appears to be the farthest advanced; it is scheduled to go into effect January 1, 1998. The federal government is the largest consumer of electricity in the United States, spending several billion dollars per year to power its military installations, office buildings, and other facilities. Potentially, the federal government could save millions of dollars per year through competitive procurement of electricity. However, federal agencies, which are classified as retail, not wholesale, consumers of electricity, are currently barred from buying electricity competitively by section 8093 of the 1988 Defense Appropriations Act.

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EXECUTIVE SUMMARY

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ISSUES AND CONSIDERATIONS The Federal Facilities Council convened a conference of legal, regulatory, procurement, and industry experts from the public and private sectors and academia to identify the emerging issues in the electric competition debate, including risks and opportunities for federal facility operators. Each speaker provided factual information and was asked to express his personal opinion and perspective on the direction of the debate. The speakers were not asked to come to any consensus on the issues or recommendations for federal facility operators. However, several key issues and considerations did emerge from the individual presentations that are included in this report, as follows: Jurisdictional issues. As noted above, FERC and the states have different authorities and responsibilities for regulating the electric industry. The states' authority to order retail wheeling has been questioned, and some speakers noted that the issue will likely be litigated. To date, the states appear to be moving forward on varying schedules with varying proposals for retail wheeling. How, or if, the two levels of government will work together as joint regulators to make the industry more efficient overall is an issue which remains to be resolved. Timing. While FERC is moving ahead with competition for wholesale buyers of electricity, it is not clear how quickly the states will proceed with retail wheeling. Given the complexity of the issues involved, the process is not likely to be a smooth one and the amount of time it will take is open for discussion. Most speakers felt that retail wheeling is inevitable. Several speakers thought that retail wheeling would come about in the next few years and warned of the need to begin planning now for that eventuality. Another speaker, however, cited the experience of regulatory reform in the telecommunications industry, which began in 1959 and is still not finished. Stranded investments or stranded costs. In the traditional regulated environment, utilities were obliged to serve their customers. To do so, utilities needed to build enough power generation capacity to serve current and forecast demands for electricity. Because utilities made investments in facilities for that purpose, they expected to recover the costs through future

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EXECUTIVE SUMMARY

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billings. Competition in power generation will render some of these facilities uneconomic and the investments will potentially be "stranded," or unrecoverable. Analysts estimate the total costs of potentially stranded investments at between $75 and $200 billion. How, or whether, utilities should be reimbursed for these investments, which were made in good faith, is a major unresolved issue in the electric competition debate. If the utilities are to be reimbursed, in whole or part, who should pay and how? Based on the presentations, the manner in which this issue is resolved, or not resolved, will be one of the most significant factors in determining how quickly and how smoothly competition is implemented. Special purpose programs. In a traditional regulated environment, state utility commissions often required utility companies to provide special purpose programs, such as research and development, demand-side management, rate assistance to low income households, energy efficiency audits, renewable energy, and the like. In a competitive market, it is not clear how or whether such programs would be paid for or what the impacts will be if such programs were curtailed. Reliability and universal service. Utilities have been required to provide for a reliable transmission network that is accessible to all customers. With the introduction of competition and the emergence of new entities, it is unclear what the impacts may be on the reliability of the system and access by customers. For example, if a customer chooses to buy electricity from a nonlocal generator, what responsibility will the local utility, which owns the wires across which the electricity is transmitted, have to the customer? Industry restructuring and customer choice. How the electric industry will be restructured is not yet clear, but the way in which it is done will influence customer choice. Speakers from California, New York, and Pennsylvania described several models that may result from competition. Elements of the model for California, for example, include an independent system operator for transmission and distribution, a competitive wholesale power pool or power exchange, and customer choice of options. These options range from choosing a "bundled," full service, flat rate from a local utility, under which a customer would observe little or no change in electric services except in the way his or her bill is structured, to options for real-

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EXECUTIVE SUMMARY

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time rates that would encourage customers to shift their usage to lower cost periods to reduce their electric bills. Barriers to energy efficiency. The Energy Policy Act of 1992 and a series of Presidential executive orders have established the goal of reducing energy consumption about 30 percent below the 1985 consumption by the year 2005. The Federal Energy Management Program (FEMP), which has the task of leading the energy efficiency effort, estimates that since 1985 energy efficiency measures have saved the government $9 billion. However, there are institutional, policy, procurement, information, and funding barriers to implementing even more energy efficiency measures. FEMP is seeking to overcome these barriers through working groups and collaboratives, and by offering technical assistance, information and training to federal agencies. Competitive procurement of electricity for federal facilities. As noted above, federal agencies are currently prohibited from procuring electricity competitively by section 8093 of the 1988 Defense Appropriations Act. However, this law is under review, and several agencies are studying the potential impacts of a change in the law including undesired societal consequences. Several speakers expressed the opinion that significant savings could result if the law is changed to allow competitive procurement. Other speakers were not confident that the agencies currently have the resources or training to procure electricity effectively in a competitive environment, but felt the agencies should begin to plan strategically for such an eventuality. Because of the volume of electricity procured by the federal government, agencies are important customers to local utilities. Several speakers suggested that agencies use this leverage to negotiate lower rates with local utilities, which fear losing federal customers in a competitive environment. It was also noted that significant cost savings can be realized through existing energy management programs, separate and apart from electric competition. Lastly, concern was expressed that the agencies not lose sight of their primary objectives of providing mission support, quality of life, and a productive working environment in the effort to reduce electric power costs.

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THE FEDERAL ENERGY REGULATORY COMMISSION'S OPEN ACCESS RULE

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THE FEDERAL ENERGY REGULATORY COMMISSION'S OPEN ACCESS RULE Wilbur C. Earley Federal Energy Regulatory Commission

The Federal Energy Regulatory Commission (FERC) regulates the prices of interstate electricity transmission, access to interstate transmission services, and wholesale sales in interstate commerce. FERC regulates prices to wholesalers, not to end-users. The wholesale market is quite an active market and is growing in importance. It has three main components: • Sales among large, vertically integrated investor-owned utilities, which sell power to one another to minimize costs or improve reliability • Sales from the integrated utilities to distributors, such as municipalities and rural cooperatives that mainly operate distribution systems and in general must buy their power from others • Sales from independent power producers (IPPs) to either investor-owned utilities or small distributors. More important, interstate transmission service is under FERC's jurisdiction, and FERC's transmission jurisdiction is an important part of the electricity industry's transition to competition. It is widely believed that the generation sector of that industry can be competitive, and FERC is moving to make that sector as competitive as possible. The historic problem is that the transmission business has been, and is still, a natural monopoly. To deliver electricity, one needs access to the wires, and in any region there is usually only one owner and operator of those wires. The utilities that

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THE FEDERAL ENERGY REGULATORY COMMISSION'S OPEN ACCESS RULE

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own the regional transmission systems also own substantial generation assets. While competing generators are ready to enter the market, the transmission owners have not been very willing to give their competitors access to those wires. That barrier to entry has resulted in widely varying prices for electricity across the country, because people cannot buy and sell to each other freely, as they can in most other markets. One cannot simply put electricity on a truck and send it down a highway to which everyone has access. The resulting disparity in prices nationwide is very large. Prices range from about 14 cents per kilowatt hour on Long Island to about 4 cents per kilowatt hour in the Pacific Northwest. That evidence does not suggest the existence of a well-functioning market. To help bring about more uniform prices, FERC is working with others in the regulatory community to open generation to competition. On April 24, 1996, the Federal Energy Regulatory Commission issued two major orders, Orders 888 and 889, which we think will speed the progress of the electric utility industry toward a competitive structure. Specifically, Orders 888 and 889: • • • • • • •

Ordered all public utilities to provide non-discriminatory open transmission access Adopted comparability standards and functional unbundling to help guard against discrimination Provided for stranded cost recovery Announced procedures for sharing transmission system information Required a wholesale marketing Code of Conduct Proposed to adopt a Capacity Reservation Tariff Established a schedule for implementation. TRANSMISSION ACCESS

FERC Orders 888 and 889 deal with several major aspects of access to transmission. The first is equal access at nondiscriminatory prices. FERC Order 888 requires all public utilities to file tariffs providing nondiscriminatory access to all wholesale users. (Retail or end-users are still under the purview of the states).

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THE FEDERAL ENERGY REGULATORY COMMISSION'S OPEN ACCESS RULE

8

Second is access to transmission information. Transmission systems are very information-intensive businesses. The impact and feasibility of new transmission service depends critically on a host of highly technical data. Transmission owners in the past have had monopolies on that information. They have found it easy to refuse service on the grounds that there was no capacity available. No one had the information needed to challenge these claims. FERC Order 889 takes a step toward making this information available by requiring each transmission owner to make available an Open Access Same-time Information System (OASIS), an electronic bulletin board that will be available on the Internet. COMPARABILITY: THE GOLDEN RULE The concept of comparability is the underpinning of FERC's rule. You can look at a utility as engaging in three functions—generation, transmission, and distribution. It sells itself transmission service, in a sense, to market the services of its generating assets. A public utility transmission owner must provide transmission service to all other market participants on terms comparable to those under which it provides service to itself. We call this the golden rule: treat others the way you treat yourself. One of the major issues of comparability that FERC addresses in its rule is the requirement that a utility must provide all the transmission services it can provide—not just the services that it actually provides to itself. The Commission wanted to avoid technical arguments over whether a utility in fact provides itself the type of service that is requested by a customer. Under the new rule, any kind of transmission service the utility is capable of providing must be provided to others. ELIGIBILITY Another issue addressed in Order 888 is eligibility. All wholesale customers are eligible for transmission service under a FERC tariff. Foreign utilities are included, provided they are willing to reciprocate by giving U.S. producers access to their markets on the same terms. Certain retail customers who gain access to the interstate market with the permission of their local utilities or through their state commission's retail access programs are also eligible.

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THE FEDERAL ENERGY REGULATORY COMMISSION'S OPEN ACCESS RULE

9

ENFORCING COMPARABILITY The fact that most of the major transmission owners are also vertically integrated into the generation sector makes enforcing comparability tricky. How can FERC enforce the concept of comparability? The Commission adopted two principal means. One is called "functional unbundling." The other is the OASIS. Functional unbundling. The basic idea of functional unbundling is that, for all wholesale power transactions it makes, the utility must receive transmission service under its own tariffs. The utility must break down its transactions into a power service and a transmission service and then secure transmission service "from itself" under the same terms and with the same priority as all other market players. It cannot go to the head of the line in terms of service availability, and it cannot provide itself special price deals. To accomplish this, the utility must have a wholesale marketing function and a transmission function that are separate and deal with each other at arm's length. In addition, the utility must gain access to information about the transmission system in the same way as everyone else, which is on the electronic bulletin board called OASIS. Privileged or inside transmission information can no longer be passed between the transmission operation part of the utility and the wholesale marketing part of the utility. Functional unbundling is a way of separating a utility's marketing and transmission functions to ensure fairness. It is regarded as a minimal form of functional separation. FERC has rejected, for now, a stricter separation of functions, known as "operational unbundling." Operational unbundling would involve a formal separation of the transmission and generation functions. Many of the comments on the proposal that resulted in Orders 888 and 889 argued that functional unbundling would not work because utilities would be able to work around the functional separation and would be in privileged positions. FERC intends to give functional unbundling a chance to work before considering stronger measures. FERC has also rejected proposals for requiring corporate restructuring, or divestiture, i.e., spinning off generating assets from transmission assets. One way of accomplishing the same aims as operational unbundling would be to establish independent system operators and give them control of transmission facilities. That idea is being discussed in a number of

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THE FEDERAL ENERGY REGULATORY COMMISSION'S OPEN ACCESS RULE

10

regions in the country. It would guarantee comparability by placing decisions about investment, access, and maintenance in the hands of an independent third party. FERC has not required it, but is encouraging the industry to explore the concept. FERC has set out principles for utilities to think about when they are considering the independent system operator concept. The objective of the principles is mainly to guarantee that the entity is truly independent and that it will truly operate the system, rather than being simply an information gatherer or administrator of tariffs. OASIS. The requirement for the OASIS, or electronic bulletin board, is the second means of enforcing comparability. Each utility must post information about its total transfer capability and the available transfer capability on the system for the next hour, the next day, the next week, the next month, and so on. The object is to make information available to everybody. In addition, all requests for transmission service and all responses to service requests must be made through the OASIS. Keeping the information out in the open will limit opportunities for preferential behavior. The OASIS will use the Internet and must be implemented in October 1996. PRO FORMA TARIFF Order 888 requires that all public utilities file tariffs that offer two basic transmission services—network and point-to-point. Order 888 sets out a pro forma tariff, containing minimum terms for good transmission access. All utilities must file tariffs with these minimum terms. If they wish to stray from those terms, their terms must be better for customers. One condition of taking service under the pro forma tariff is "bilateral reciprocity." This condition is meant to address the problem that not all transmission owners are jurisdictional to the FERC; for example, publicly owned and foreign owned transmission systems are not. The bilateral reciprocity condition is an attempt to bring these owners into the open access world. Any transmission owner who takes service under a FERC tariff must promise to reciprocate, that is, to make available to the utility from whom they are getting service comparable transmission service.

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STRANDED COSTS FERC has also addressed the very sticky issue of stranded costs in its rule, but only for wholesale contracts. Under Order 888, utilities will be entitled to extracontractual consideration and given the opportunity to recover up to 100 percent of any costs stranded as a result of a customer leaving the system for another supplier. From FERC's point of view, the regulatory compact entered into by utilities and their regulators obliged utilities to serve customers. In carrying out that obligation, the utilities needed to build enough facilities to satisfy present and projected future load. Because they made investments in facilities for that purpose, utilities reasonably expected to recover the costs of those investments. But the world has changed. Competition is going to take much of that market away. As a matter of equity, FERC believes utilities are due some consideration on their stranded assets. They made investments in good faith, and they are entitled to collect the revenues to which they had a reasonable expectation. However, utilities will not be able to collect every dollar they want to collect. They will need to show FERC that these investments were made on the basis of a reasonable expectation that the customers were going to stay on their systems beyond the contract period. In addition, utilities have a duty to mitigate any stranded costs by selling some assets, selling some power, or letting customers take control of their power and try to get the best price for it. SCHEDULE The pro forma tariffs must be filed within 60 days of the issuance of the rule, that is, by July 9, 1996. Individual utilities must file these pro forma tariffs and take service under them (unbundling and sharing information as required). Immediately afterwards, utilities may ask for changes to the pro forma tariffs, as long as the changes are improvements from the customers' point of view or reflect regional practices. Large power pools must file their pro forma tariffs by the end of 1996. FERC has given them extra time to file because they have embedded arrangements and contracts and understandings with one another which need to be worked out.

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The Commission has also proposed eliminating the network service now provided for in the pro forma tariffs and replacing the current tariffs with a new capacity reservation tariff. This type of tariff would require service to be provided on the basis of capacity rights to inject and withdraw specific amounts of power from specific points of receipt and delivery. Organizing transmission service this way should result in better planning and facilitate a resale market. A technical conference will be held and comments received on this proposal in the fall of 1996.

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ELECTRIC POWER COMPETITION: PERSPECTIVE OF A REGULATOR

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ELECTRIC POWER COMPETITION: PERSPECTIVE OF A REGULATOR

Commissioner John Hanger Pennsylvania Public Utility Commission

My perspective is that of the Pennsylvania Public Utility Commission. I think Pennsylvania offers a useful microcosm of the nation. Ideally, there should not be a debate about whether competition is good or bad, and we should immerse ourselves in all the detailed economic issues that must be considered in determining how to create a system that brings the total costs down for everyone. But let me assure you, as a state regulator, that we are at a much more basic level, asking whether competition is a good idea or not. The answer to that question is not always derived from a purely technical analysis. I am one of those commissioners who believe that we should engage in price regulation in this society only to the extent that a product or service is a natural monopoly. If a product or service is not a natural monopoly, I believe in letting the competitive market regulate price. To me, price regulation is a very different issue from environmental regulation or health or public safety regulation. Certainly, those forms of regulation are necessary, in my judgment often, even when products or services are competitive. I had thought there was rather wide consensus about that principle. Then I read the headlines in the Washington Post a few days ago, saying, ''Government To Look at Gas Prices," because gasoline prices have gone up 10 percent in a few months. Yesterday there was a headline reading, "Government To Look at Beef Prices." They are too low, so we are going to try to raise beef prices. Most Americans profess to love a competitive

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market, but sometimes when the market moves in a particular direction some of us get very nervous. Nonetheless I believe that, so long as a product or service is not a natural monopoly, we should let the market rule. Intervention would be appropriate only if monopoly power prevents the market from functioning effectively, and only to the limited extent necessary. Many regulators may agree rhetorically with those statements, but in practice they are what I would call protectionists, who are looking to protect the monopoly. Electric competition started in 1978 with the Public Utility Regulatory Policies Act (PURPA). Congress passed this act in reaction to the energy crisis of the 1970s. Its intention was not particularly to create competition, but rather to diversify the mix of fuels that plants used to generate electricity. Much of the electricity in this country in the 1970s was generated from oil; today, other fuels have largely replaced oil. The 1978 act has had the unintended consequence of turning generation into a clearly competitive function. Nearly all existing plants at that time were built by public utilities, companies with monopolies granted by state governments. By 1996, more than half of all new generation plants built in this country will be built by companies that do not have monopoly franchises (often called independent power producers or nonutility generators). That 20-year experience with the independent power business shows regulators that this business really has three main segments: generation, transmission, and distribution. Generation is generally agreed to be a competitive function. Society does not need to give a company an exclusive franchise to build a generation plant in order to get the least-cost generation supply. Transmission and distribution, on the other hand, are generally agreed to be natural monopolies still. The term "deregulation," as applied to the electric industry, is inaccurate. I am not aware of anyone who is proposing any policy option that would in fact deregulate the industry. What is being discussed instead is the deregulation of the price of generation by allowing customers to choose their generation suppliers through the existing transmission and distribution system. Transmission and distribution would remain among the most fully regulated industries in the economy. All customer service and safety regulation could remain just as it is now.

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In 1992 Congress passed the Energy Policy Act. This act gave the Federal Energy Regulatory Commission (FERC) authority to require transmission owners to open access to their systems to third party suppliers of energy. It also authorized FERC to require that those owners charge rates that are comparable to the rates the transmission owners charge their own customers. In April 1996 FERC published its rule implementing these provisions of the act. FACTORS CREATING COMPETITION AND CUSTOMER CHOICE A number of factors have driven policy toward creating competition and customer choice in the electric industry. Advances in technology have lowered generating costs. Legislation such as PURPA and the 1992 Energy Policy Act have opened up markets. The changing economics of utilities permits any number of nonmonopoly companies to build smaller, more efficient generation plants in a much shorter time than previously was possible. The more competitive global economy has brought opportunities to buy and sell power and generation assets worldwide. Finally, the failure of regulation to produce uniform and reasonable rates has led to calls for relief from consumers. ROLE OF ELECTRICITY IN THE ECONOMY The debate is important, because electricity is central to the economy. We spend more than $200 billion each year on electricity in this country—more than we do on oil, unleaded gasoline, and heating fuel combined. Electricity will be the dominant fuel of the 21st century. In view of all the recent attention to gasoline prices, it is surprising that we rarely see blaring headlines or calls for congressional or Justice Department investigations into the cost of electricity. The reason is that most people don't know what they are paying for electricity. It is not a traded commodity, by and large although that is changing rapidly. To find out what electricity costs one must look through thousands of pages of tariffs from 50 state commissions, in addition to many special contracts that have been approved and sometimes permitted to remain confidential. Pennsylvania spends $10 billion per year on electricity. It is vital to our energy-intensive manufacturers, many of whom spend 20 percent of

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their total production costs on electricity. Some spend as much as 70 percent. In steel and some other industries, such as glass making, the cost of electricity is more than the cost of labor. For those reasons, electricity prices are an important site selection criterion for plants and industries. The cost of electricity is not only a concern of big business. Families also spend a lot of money on utilities. In Pennsylvania, the average family works from the first of January to the middle of February to pay the bills for light, heat, water, telephone, and sewer service. Families living in poverty may spend as much as half of their income on utility bills, with 15 percent of their income required for the electric bill. ELECTRICITY PRICES AS A SOURCE OF COMPARATIVE ADVANTAGE Table 1 shows the remarkable divergence of electricity prices among Pennsylvania utilities over a period of 20 years; I suspect many states would show a similar pattern. In 1970 the spread between the high-cost producer and the lowcost producer was relatively narrow, less than one-half cent per kilowatt-hour, or about 25 percent. By 1990 the spread was enormous: more than 7 cents per kilowatt-hour (actual price without Table 1. Average residential price of electricity in cents per kilowatt-hour, 1970 and 1990 Utility

1970

1990

Duquesne Light Co.

2.51

12.20

Metropolitan Edison Co.

2.30

8.01

Pennsylvania Electric Co.

2.28

7.86

Penn Power Co.

2.39

9.96

Pennsylvania Power & Light Co.

2.07

7.92

PECO Energy Co.

2.54

12.58

West Penn Power Co.

2.15

5.04

2.32

9.08

Pennsylvania Average

SOURCE: Pennsylvania Public Utility Commission, Electric Power Outlook, July 1993.

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17

any adjustments). The spread between the low-cost and high-cost producers had become well over 100 percent. What happened? Bad, or unlucky, management and regulatory decisions were made. Table 1 indicates a failure of regulation. West Penn Power would be the prominent exception. In other cases we had enormous failures, such as PECO's climb from 2.54 to 12.58 cents. (One underlying fact is that West Penn did not invest in nuclear power, and PECO invested very heavily in nuclear power.) PECO (in the Philadelphia region) has the 9th highest residential rate in the nation. Duquesne (in the Pittsburgh area) has the 14th highest rate. As a result of the failure of regulation, PECO and Duquesne residential customers pay more than 100 percent more than West Penn's customers. When I travel around the state, people often ask me why their companies or families are paying twice what their competitors or relatives are paying a few miles away, in another utility service territory. That is a very good question, which has no good answer. Pennsylvania's average rates are 15 percent higher than the national average. We spend $10 billion per year. If rates were 15 percent lower, at the national average, Pennsylvania's annual electricity bill would be $1.5 billion lower. That savings would have an important economic impact. In commercial and industrial rates we see similar ranges in price in Pennsylvania. (The industrial rates are subject to various special contracts at this point, so it is difficult to track them.) If we compare Pennsylvania's average industrial rates with those in other Atlantic seaboard and Midwest states (Table 2), you see large differences again, with Pennsylvania near the middle. Of the states in the region with higher prices than Pennsylvania, New Hampshire, Massachusetts and New York are, not surprisingly, among the most aggressive states in moving toward retail competition. They have decided to allow all customers to have retail choice starting in 1998. New Jersey is another state with high electricity prices. Governor Whitman has just announced her intention that New Jersey permit customer choice soon. In Pennsylvania there are three bills in the legislature; hearings have already begun. The Commission issued its report on July 3, 1996 recommending a transition to customer choice. Pennsylvania is already at a competitive disadvantage in electricity rates with neighboring states, including Ohio and Maryland. Table 2 would look much worse if it included states such as Wisconsin and Kentucky and a number of others. We are mindful that the neighboring states with which we do have a

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competitive advantage in electricity rates are the very states that are moving aggressively to open their markets to competition. Table 3 shows how selected Pennsylvania and U.S. rates compare with those of some European countries. In global terms, the average U.S. rate, and even the average Pennsylvania rate, is actually very good. Some have interpreted that fact to mean that the system is working well enough. But the average U.S. rate, like the average Pennsylvania rate, conceals great variations. Furthermore, electricity ought to be one of the industries in which the United States has an enormous comparative advantage in TABLE 2. Average industrial electricity prices in cents per kilowatt-hour, summer 1994 State

Average industrial rate, cents/kWh

New Hampshire

9.35

Massachusetts

8.61

Connecticut

8.59

New Jersey

8.16

New York

7.82

Pennsylvania

6.17

Ohio

4.76

Maryland

4.61

Delaware

4.42

Virginia

4.11

Indiana

4.10

West Virginia

3.99

U.S. Average

5.14

SOURCE: Edison Electric Institute, Typical Residential, Commercial and Industrial Bills, Summer 1994.

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ELECTRIC POWER COMPETITION: PERSPECTIVE OF A REGULATOR

TABLE 3. Comparison of Selected Pennsylvania and U.S. Rates to Some European Countries COUNTRY

COST (cents per kwh)

PECO Energy Company (residential rate)

12.74

Duquesne Light Company (residential rate)

12.71

Germany

11.88

Italy

10.00

PECO Energy Company (average rate)

9.8

Portugal

9.65

Duquesne Light Company (average rate)

9.17

Belgium

9.12

Spain

8.50

Britain

8.09

Pennsylvania

7.88

Luxembourg

7.62

Ireland

7.40

France

7.39

Netherlands

7.27

United States

7.01

Greece

6.87

Denmark

5.89

Finland

5.72

Norway

4.72

Sweden

4.22

Source: Wall Street Journal. No date.

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international competition. If we want to have high wages and a high standard of living, we must have comparative advantages, whether they are found in education or the cost of capital or electricity infrastructure services. We need to get every ounce of comparative advantage achievable from the electric industry and the energy industry generally. Pennsylvania has lost more than 300,000 manufacturing jobs since 1980, and more than 14,000 jobs in the last 12 months. From 1983 to 1993, manufacturing establishments in Philadelphia dropped from 2,154 plants to 1,537, and 85,900 manufacturing or construction jobs were lost—a loss of 50 percent. Pittsburgh experienced a 30 percent decline in jobs, from 103,300 to 73,000, over the same period. Electricity costs are not solely responsible for these losses, but they have contributed to them. The debate over competition is being driven by these concerns. Every state is trying to make itself business-friendly and competitive, particularly for high-wage manufacturing employment. TRANSITION ISSUES A variety of issues will face the nation as states move toward retail customer choice. These include stranded investment, reliability, universal service, conservation and environment quality, and the obligation to serve. Stranded investments. Stranded investments are mainly costs of generation plants that are above the likely market price for electricity if retail customers are allowed to shop. Stranded investment is at the top of nearly every utility's list of concerns about competition, because they want to be sure they can recover the costs of past investments. Some low-cost utilities have argued that there should be no recovery of stranded investments. West Penn Power Company, for example, the company in Pennsylvania with the lowest costs, has taken that line. They view stranded cost recovery as a bailout of their future high-cost competitors. PECO and some other companies facing large stranded investments, on the other hand, favor 100 percent recovery. Nationally, estimates of stranded investment range from $75 to $200 billion. In Pennsylvania the figure is roughly $6 to $10 billion. These sums are a tremendous indictment of traditional regulation. If regulators had

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been doing an effective and efficient job, we wouldn't be talking about stranded investments of that magnitude. But we are. The question is who pays for it. Today, all existing customers are paying for stranded investment as reflected in rates. Shareholders pay none of it, under tariffs approved by regulators like myself in the past. The question is whether, when retail choice arrives, consumers will continue to pay 100 percent of that stranded investment or whether shareholders will bear all or some of these costs? One of the dangers in stranded investment is cost shifting, which is occurring today. By cost shifting I mean transferring costs from one class of consumers to another. Stranded investment solutions, first of all, should involve no cost shifting. Those investments are all reflected in rates now, pursuant to formulas that allocate stranded investments among the various customer classes. So long as that allocation is respected, cost shifting will not take place, even if regulators provide for 100 percent recovery of stranded investments. The second part of the solution is mitigation. Utilities should be required to reduce the amounts of stranded investments they hold. There are things that they can do, and many are doing those things aggressively. Even so, stranded investments will remain, and we will need to decide how much to allow to be recovered in the future. And we will need a mechanism for collecting it. A "wires charge" on the regulated transmission and distribution service that must be used by all retail consumers could be collected during a transition period of perhaps three to ten years. Such a mechanism would ensure that all utilities and consumers pay a fair portion of stranded investment. Reliability. Maintaining reliability requires careful planning; it is good now, and we must make sure nothing happens to change that. Use of an independent system operator to coordinate all transactions on the existing interconnected power grid provides an opportunity to maintain, or even improve, system reliability. Universal service. Universal service must be maintained. Electricity is a necessity of life. Pennsylvania had 43 deaths in six years as the result of utility services being terminated. Those deaths were caused by fires due to candles, kerosene heaters, and other dangerous heating and lighting

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substitutes. Three senior citizens have frozen to death in their homes in Pennsylvania in that same period. In my state, utilities incur a bad debt expense equal to about 2 percent of revenues. That bad debt is not due only to customers with limited and fixed incomes. The middle-income family that moves to Florida, doesn't pay its last bill, and cannot be found also contributes. If that amount of money, roughly two percent, were collected in the form of a wires charge and distributed to and targeted appropriately to low income families, we could probably improve our rate of universal service in Pennsylvania. Conservation and environmental quality. Environmental standards, such as those concerning clean air, are not established by public utility commissions. They may stay the same or be modified, whether or not generation becomes competitive. Conservation programs are built into many utility rate structures. They may continue to be provided by the local distribution utility, just as they are now. The economic basis for such programs would probably become end-use efficiency instead of avoided generating costs. Renewable energy sources and other "green" technologies will get a real boost from customer choice. Consumers now must use whatever fuel their monopoly generator chooses. They will be able to choose green fuels if they prefer. Wind power already can be produced at less than 5¢ per kwh, while nuclear power can cost more than 10¢ per kwh. Yet we have lots of nuclear power and no wind power in Pennsylvania. Solar power is not yet cost-competitive primarily because of limited production. If green consumers choose solar power, the industry will develop economies of scale and more competitive prices sooner than it otherwise would have. Obligation to serve. Utilities have a traditional obligation to serve, that is, to connect all customers in a service territory and provide them with power of certain specifications. That obligation will be reexamined in a competitive retail market. Does giving retail customers a choice imply that the utility is no longer obligated to serve? If you go to a restaurant, they do not have to serve you, they can close whenever they want, and they can decide what menu items to offer. The obligation to serve does not exist normally in the market. What form would it take in a competitive retail market for electricity?

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Remember, generation is likely to be subject to competition, but natural monopolies will remain in transmission and distribution. On that basis, most people agree that, in the future, utilities will have the obligation to connect all customers to the system, and to allow electricity to flow over that system. Utilities will have a contractual obligation to supply electricity to customers who wish to remain with their local utilities. But that obligation, most people agree, would not apply to customers who decide to go shopping for outside generation; for them, the utilities' obligation is simply to connect and deliver. It would be up to the customer to enter into contracts to secure the new source of electricity. FOUR MODELS OF INDUSTRY RESTRUCTURING There are four fundamental models of industry restructuring: 1. Simply maintaining the monopoly and improving it, for example by performance-based ratemaking and allowing wholesale competition. This model would not allow for customer choice, for the most part. This is the model being proposed by what I call the protectionists in the debate. They are the people who do not want too much change. 2. The ''pure poolco" model, in which all generation would be competitively priced, sold into the pool, and bought from the pool. The retail price of generation would be charged to equal the pool's competitive price. This model is being advanced by Professor William Hogan and some of the California utilities. 3. A voluntary power pool, unlike the mandatory pool in model 2. Generation would be bought and sold on the basis of competitive bidding. One could buy generation from the pool, or one could make direct contracts with suppliers. 4. Exclusive use of direct contracts. Customers would have authority to purchase electricity directly from any generator. No competitive pool would be created, although one might develop naturally.

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California is moving toward a market structure similar to model 3. I suspect that, over time, that kind of market structure will develop around the country. Norway has a similar system, in which about 30 percent of the transactions are done through the pool, and 70 percent on a retail bilateral basis. HOW CUSTOMERS WILL CHOOSE ELECTRIC GENERATION SERVICES When the new industry structure is fully in place all retail customers will be able to choose among several alternative sources of electric supply. The market will develop a range of choices that accommodate the needs of different customers with different requirements. Choices will be available not only for customers with considerable time and knowledge to follow power markets, but also for those who prefer "one-stop shopping." All customers will continue to receive local distribution services from their existing utilities. Customers could instruct their local distribution utilities to deliver electric generation services on their behalf by selecting such options as: • Paying rates set by the Public Utility Commission, just as they do now. This option could remain available through a transition period for any customer not choosing another option. • Buying from a particular generator through a direct contract. With this option, consumers preferring a particular type of generation or related services could more precisely purchase the services they wanted or obtain volume discounts by purchasing for multiple facilities. • Through a spot market at an average price. This option would make the same market rate available to all consumers so as not to require significant effort or knowledge by consumers. This option would make the benefits of restructuring available to all consumers equally. • Through a spot market at an hourly time-of-use price. With this option, consumers who were able to adjust their usage to off-peak hours would achieve even greater savings.

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ELECTRIC POWER COMPETITION: PERSPECTIVE OF A REGULATOR

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• Through aggregators, such as marketers, brokers, local governments, or purchasing cooperatives. This option is a secondary form of direct contracting. A third party would assemble a group of consumers, to obtain the broadest range of services without requiring knowledgeable, active involvement by consumers. • Through the local distribution utility providing electricity as an aggregator. This option would provide another competitor for consumers and give existing utilities an equal opportunity to provide generation to their present customers. CONCLUSION The debate is an exceedingly important one. I urge federal facilities in Pennsylvania and around the country to approach their commissions and become part of that debate. Some have already done so. Now is the time to speak up.

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A ROADMAP TO ELECTRIC RESTRUCTURING IN CALIFORNIA: DECISIONS 95-12-063AND 96-03-022

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A ROADMAP TO ELECTRIC RESTRUCTURING IN CALIFORNIA: DECISIONS 95-12-063And 96-03-022 Douglas Long California Public Utilities Commission

I will discuss the process the State of California has used in developing a proposed market structure; the goals and objectives of electricity restructuring in California; the proposed market structure; transition costs; customer choice; the role of the utility in restructured industry; some of the major current issues; and the state's schedule for implementation. PROCESS The California Public Utilities Commission began the process of moving toward competition in 1993, when it published a book, "Perspectives on the Electric Industry," known as "the Yellow Book." That proposal attracted public comment and discussion, on the basis of which the Commission prepared and published another book in April 1994, called "the Blue Book." The Blue Book was an order instituting an investigation of restructuring. It prompted more public comment and commission hearings. In May 1995 the Commission published two alternative potential versions of a restructured electric industry. In response, some of the major utilities and customer groups developed a memorandum of understanding that merged the two alternatives. In December 1995 the Commission published Decision 95-12-063, which outlines the broad goals of restructuring. These goals are expected to be reached by 1998. Decision 96-03-022, published in March 1996, fills in some of the details.

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GOALS FOR RESTRUCTURING CALIFORNIA'S ELECTRIC INDUSTRY The goals for electricity restructuring in California are to: • Offer consumers greater choice in purchasing energy services • Allow competition to flourish where conditions are ripe • Implement performance-based ratemaking for remaining monopoly services • Reduce the price of electricity • Continue to deliver safe, reliable, and environmentally sensitive energy services • Maintain universal, nondiscriminatory availability of electric services • Provide the utilities with a reasonable opportunity to earn a fair return on their investments • Continue to encourage the diversity of energy sources and maintain important public purpose programs. PROPOSED MARKET STRUCTURE In outline, the new market structure being proposed for California (to be put into effect January 1, 1998) has the following elements: • An Independent System Operator (ISO) for the transmission system • A competitive wholesale power pool (known as the Power Exchange) • Customer choice of options: full service utility customer, direct access to the competitive electric generation market, real-time rate options, or contracts for differences. Figure 1 puts this proposed market structure in graphic form. We expect all consumers, large and small, to benefit from a competitive market for electricity. Statewide power dispatch and competition among generators on an hourly or half-hourly basis will improve efficiency. Consumers will be able to optimize their energy use, taking advantage of off-peak power, through the use of real-time metering.

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Figure 1. Proposed market structure for State of California .

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A reduced rate of return on some uneconomic ("stranded") assets will reduce rates. We shall find out over time whether these expectations are met. In addition, rates for full-service customers will be capped for three years at the levels of January 1, 1996. At the top of Figure 1 are generators 1 through 6 in this example. Traditionally their power goes through the vertically integrated transmission and distribution systems to customers (numbered 1 through 5 in the example). Figure 2 is a more detailed view. The California Public Utilities Commission wants to change this pattern. The debate was whether to do it through a Power Exchange, for wholesale power alone, or let customers buy directly. Originally the Commission staff favored the latter approach. One advantage of that approach was that functions of the Power Exchange and the Independent System Operator could be combined in one organization. Under the proposed system, there will be two separate entities (with the Power Exchange as a wholesale market and retail customers permitted to go directly to generators). THE INDEPENDENT SYSTEM OPERATOR In the proposed market structure, the Independent System Operator controls and operates the transmission system. This arrangement will ensure that wholesale transmission for utilities is not favored over retail transmission for customers. The ISO also: • • • • • •

Coordinates scheduling the dispatch of power from all sources Balances load on a real-time basis Efficiently manages transmission congestion Maintains reliability Recovers the costs of ancillary services Provides information on transmission constraints, load distribution, line losses, and other system conditions.

The ISO will be structured to be independent of the utilities and the Power Exchange. The ISO will not own the transmission system, but will

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Figure 2. California's restructured electricity market.

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make operating decisions. (The transmission system will continue to be owned by the utilities). Approval by the Federal Energy Regulatory Commission will be required beforehand. THE POWER EXCHANGE In the proposed market structure, the Power Exchange will provide a market for power with published hourly and half-hourly prices. It will be a competitive, wholesale power pool that will allow power producers to compete using transparent rules for bidding into the exchange. The power exchange will match supply bids with bids from utilities, power marketers, and others, rank the bids on a least-cost basis and then submit the proposed schedule for delivery of power to the Independent System Operator. The Power Exchange will also show a visible price for customers help them to make efficient purchasing decisions and adjust their consumption. The structure of the Power Exchange will ensure that it is separate and independent from the Independent System Operator. Furthermore, it will have no financial interest in any source of generation. Like the ISO, the Power Exchange must be approved by the Federal Energy Regulatory Commission. Municipalities, independent power producers, out-of-state producers, and public utilities will be able to participate in the Power Exchange, but their participation will be voluntary. During the five-year transition period, Pacific Gas and Electric, San Diego Gas and Electric, and Southern California Edison are required to purchase all of their energy requirements for full service customers through the Power Exchange. They are also required to bid into the Power Exchange until their generating plants are valued in the market. To reduce the "horizontal" market power of utilities (due to their ownership of the vast majority of generating plants), the largest investor-owned utilities, Southern California Edison, San Diego Gas and Electric, and Pacific Gas and Electric will be required to divest themselves of some generating assets.

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TRANSITION COSTS Transition costs are the costs associated with utility assets and obligations that become uneconomic in a competitive environment. Such costs and obligations include the above-market-value portion of the undepreciated fixed costs of generation assets; costs of generation contracts if prices prove to be uneconomic in the future; and other generation-related costs that are completely unavoidable. By 2003, all non-nuclear generating assets will be held out for sale or appraisal. Rates for nuclear generating assets will be determined separately under an alternative ratemaking proposal. Every generating asset must be assigned a value, to identify those that are overvalued or undervalued on the books, compared with their market value. The difference between the market price and what is on the books is what we call a "Competition Transition Charge" (CTC). A share of the transition cost will be paid by every electricity customer of an investor-owned utility. Utilities will recover all transition costs, but they will earn a lower return on equity for uneconomic assets. Rates for bundled electric service will not rise above January 1, 1996 rates. The CTC will be collected only until 2005. The Commission's preferred policy also states that the CTC cannot be "bypassed" by customers. Nor will there be any cost shifting among customer classes. MARKET CHOICE FROM THE CUSTOMER'S STANDPOINT Figure 1 shows the two fundamental options for customers. Whether a customer is making a direct access transaction or making Power Exchange purchases from a utility, he or she must deal with the Independent System Operator, and with some form of local distribution utility. If a customer decides not to stay with the bundled full-service flat rate from the local utility, many options present themselves. With a direct access option, retail customers can choose to arrange the purchase of electric generation service directly from nonutility generation providers. Customers will also have the choice of a real-time rate option which will allow customers to shift their use to lower cost periods, reducing their electricity bills. Under this option, distribution utilities will offer tariffed electric service referencing the real-time price published by the Power

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Exchange. Customers may also enter into contractual arrangements that allow for the allocation of risks associated with market uncertainties and price volatility. Customers will also be dealing with aggregators of all kinds who will be telephoning, seeking to sell their products and services, and probably interrupting the customer's evening meals, much as the long-distance telephone companies do today. THE ROLE OF THE UTILITY IN A RESTRUCTURED INDUSTRY Among the other issues we face in California, and probably nationally, are municipal utilities' having competitive advantages over utilities that now exist. Municipal utilities are able to issue tax-exempt bonds at a lower cost than the debt issued by investor-owned utilities. Municipal utilities may arguably be able to control or prevent competition within their territories. In the period of transition to competition, customers may abandon the utilities for municipal and other power companies, leaving the remaining customers to bear the full transition charges. Utilities under the California Public Utility Commission's jurisdiction will have the following functions: •

Provide safe, reliable, nondiscriminatory distribution service to all electricity customers • Provide energy from the Power Exchange to all customers who do not choose or are not eligible for direct access (so-called full-service customers) • Provide service under incentive ratemaking rather than cost-of-service ratemaking for distribution and utility-owned generation assets. PUBLIC PURPOSE PROGRAMS AND RATE-SETTING Among the major issues that California is still looking at are public purpose programs and rate-setting. Public purpose programs are functions utilities have come to serve that are considered to be in the public interest, but are not in the immediate interest of the utilities. Utilities support research and development, energy efficiency assistance to customers, rate assistance to low income customers, and the like. Some of these functions

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will need to be provided in other ways in the future. Surcharges for research and development, energy efficiency programs, and low income rate assistance and efficiency services are included in the plan. It also includes a renewable energy purchasing requirement. Rate-setting also is a complicated issue. Rates will need to be established for both transition costs and unbundling pricing. We need to break out those costs and separate them in order to seek approval before FERC for transmission rates charged by the Independent System Operator. SCHEDULE FOR IMPLEMENTATION Our goal is to have the new market structure in place by January 1, 1998. Essential actions that are needed prior to January 1, 1998, include the following: • ISO principals and rates approved by FERC and asset transfer approval by the California Public Utilities Commission • Power Exchange approved by FERC and asset transfer approval by the California Public Utilities Commission • Resolution of horizontal market power issues • Rates unbundled and applicable tariffs established • Adoption of direct access eligibility and phase-in protocols • Adoption of direct access standards including billing and access charges • Adoption of metering standards • Installation of metering equipment • Adoption of competition transfer charge mechanism; forecast of costs articulated • Establishment of rules for new estimates • California Environmental Quality Act completed and Environmental Impact review official • Consumer protection in place: service and safety issues and education trust • Public goods charge in place.

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THE RESTRUCTURING OF CALIFORNIA'S ELECTRIC INDUSTRY: A UTILITY'S PERSPECTIVE

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THE RESTRUCTURING OF CALIFORNIA'S ELECTRIC INDUSTRY: A UTILITY'S PERSPECTIVE John L. Jurewitz Southern California Edison Company

In California, as in the rest of the Union, the traditional structure of the electric utility industry has been typified by local franchises for distribution and retailing, with vertical integration all the way up to generation. Generation was regulated as to price on a cost-of-service basis. Voluntary transmission service was the rule prior to the Energy Policy Act of 1992. The Energy Policy Act placed every state in a kind of intermediate position, in which there is wholesale competition, with mandatory wholesale transmission. Meanwhile, the Federal Energy Regulatory Commission (FERC) has moved in the past 5 to 10 years toward market-based price regulation for stand-alone generation, as well as utility generation in some circumstances. The entire nation is likely to move in the next few years, state by state, toward retail competition all the way down to the individual customer. Local distribution franchises, regulated by state commissions, will probably remain. Utilities will undoubtedly face at least partial divestiture of generation assets; in California, utilities are being asked to divest themselves of 50 percent of the fossil generation within their service territories. Both Pacific Gas and Electric and the Southern California Edison Company, within the past five or six weeks, have filed proposed processes for making such partial divestitures. It is important to recognize that generation is not, in fact, being deregulated. It is regulated by FERC under the Federal Power Act, and it would require an act of Congress to move away from regulation of

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generation. What FERC has done instead is to adopt market-based pricing standards. The significant change we are facing in California, as we move toward mandatory retail transmission access, is to abandon the traditional collective decisions about generation stations and supply sources statewide. Instead, those choices will be made by the market. BENEFITS OF AND CONCERNS ABOUT RETAIL ACCESS The potential benefits of retail access are substantial: • Greater choice for customers. In the United States choice is of value in and of itself, even if customers happen to do the wrong thing or unlucky things with those choices. We all recognize the value of individual freedom to make our own choices and live with the consequences of those choices. • Privatizing the risks of resource choices. The private sector, not consumers, will bear the risks of resource choices. U.S. utilities that have high costs generally do so for two main reasons: (a) investments in nuclear generation and (b) contracts entered into with so-called ''qualified facilities" (that is, independent power producers from whom utilities must purchase power pursuant to the Public Utility Regulatory Policies Act of 1978). In California these two factors contribute about equally to the high costs of utilities. • Depoliticizing resource planning. Resource planning will be depoliticized. In the process that the California Public Utilities Commission has used, the only thing that all could agree on was that the biennial resource planning process, in which regulators would decide ultimately when and how resources would be added, had become unwieldy and politicized. Southern California Edison viewed it as something of a pork barrel for supply-side interests, through which utilities were required to add capacity that was not needed to maintain reliability. With the Commission's adoption of retail access, it has slashed this

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Gordian knot by simply letting the market decide what is to be added. • Reducing long-run costs. Costs will be reduced in the long run. In the short-term, on an instantaneous hour-to-hour and day-to-day basis, electricity markets are relatively efficient. For that reason, I believe we will find, as we get the Power Exchange underway, that spot market prices will not change much. There is already a very active wholesale spot market with many participants in the western United States. The price disparities within and between states are the result of long-term resource commitments, not the result of paying more or less on the spot market. Everyone pays just about the same amount on the spot market from hour to hour. In the long run, costs will be reduced because competition among suppliers will do a better job of holding down costs and stimulating innovation than to continued cost-of-service regulation. Many concerns have also been raised about retail access: •

Jurisdictional concerns. Serious jurisdictional ambiguities and potential shifts in state and federal authority need to be addressed. • Increased costs. Some costs may be higher. Transactions costs will certainly be higher; such costs will need to be offset by certain other benefits. The system may also lose least-cost dispatch, depending on how perfectly and frictionlessly the new market works. The Power Exchange and private dispatch operations, in my company's view, will combine to improve least-cost dispatch, through competition. • Stranded system obligations. Stranded generating assets are obviously important concerns. These obligations should not be allowed to result in cost shifting among customers. Small customers fear they will be left to bear all of these costs if large customers go elsewhere for their generation. Utilities are concerned that their shareholders will bear these costs.

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• Loss of support for public purpose programs. Loss of support for public purpose programs such as renewable energy, demand-side management, and low income rate assistance are all real concerns. • Reliability. The reliability of the system, for which no single entity has complete control, is a serious, but we think resolvable, concern. These concerns are not reasons for maintaining the status quo ante. They are reasons for going forward cautiously and deliberately, while developing reasonable solutions. JURISDICTIONAL CONCERNS Ambiguities of jurisdiction between state and federal regulation are certain to be controversial as competition takes hold. The duty of regulators at both levels is to establish a clear dividing line between federal and state regulatory responsibilities and jurisdictions. Several serious issues deserve special attention. Supplier regulation. One problem suppliers face in the new regime is the existence of long-term contracts with so-called qualified facilities. Under the federal Public Utilities Regulatory Policy Act of 1978, these independent generators must be paid on the basis of "avoided costs" by utilities, that is, according to a generous formula based on the costs the utilities would have incurred by adding equivalent amounts of their own capacity. Utilities view that requirement as inconsistent with a competitive market. Federal legislation would be required to level that playing field. On the other hand, owners of qualified facilities fear that removing this requirement would not level the playing field, but rather tilt it in the opposite direction. They propose waiting until a competitive market has been established and tested. Their concerns are legitimate. It will be necessary simultaneously to ensure that competitive institutions are in place and that no group has an unfair advantage. Nonqualified facilities sales are regulated by FERC. "Exempt wholesale generators" (i.e., independent generators exempted from the Public Utility Holding Company Act pursuant to the Energy Policy Act of 1992) cannot sell to retail customers—not even to the federal government.

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Following the path that California is taking will require reexamining these prohibitions at the federal level. Transmission access authority. FERC has the power to order mandatory wholesale wheeling, but the Energy Policy Act specifically forbids the Commission from ordering retail wheeling. On the other hand, states may not have the authority to order retail wheeling. They may be federally preempted from doing so. That issue will be litigated. In fact, nearly everything will be litigated, as interest groups appear on all sides of these jurisdictional issues. Transmission pricing authority. FERC has authority over all interstate transmission pricing, and has affirmed that principle in its recent Order 888. States cannot set prices for retail interstate wheeling. But virtually all transmission is in interstate jurisdiction; even unbundled distribution service may be found to be in interstate commerce. FERC would like to carve out for states a jurisdiction over distribution wire service, with a clear dividing line between state and federal jurisdiction. States would then be able to attach their charges for public purpose programs and stranded costs to the distribution tariffs or delivery charges. Still, unbundling transmission and distribution services makes room for many different legal theories. One theory holds that unbundling transmission places the entire wire conduit, regardless of voltage level, under FERC jurisdiction. In other words, the theory implies, there really is no substantive distinction between transmission and distribution. The states would not be happy about such a finding. BASIC ISSUES IN RETAIL ACCESS Restructuring of the market. The high points of the California Public Utilities Commission decision were (a) the establishment of the Power Exchange, (b) the provision for direct access by 1998, (c) establishment of the Independent System Operator, (d) stranded cost recovery through a Competition Transition Charge, and (e) funding of environmental and public policy programs by nonbypassable charges. The Independent System Operator's function is much like that of an air traffic controller. Some entity must ensure that the resources are in

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balance with the loads and that the system is reliable. One should not regard it as simply regulatory meddling. The question is how best to structure that entity. The service must be provided on a nondiscriminatory basis, which is why California is moving toward an independent System Operator that has no commercial interest in any of the buyers or sellers. California also has the Power Exchange, which conducts hourly auctions, as a spot market in power (with bids submitted the day before). If there were no formal power exchange, an informal power exchange would arise to serve the demand for hour-to-hour dispatch. Customer choices. California customers' choices would appear to fall in four categories: • Retain the current utility tariffed service. If a customer does not want to do anything in response to the new market structure, he or she will not have to do anything. The customer should not notice any change. • Choose a real-time-pricing utility service tariff that will flow through to customers from the Power Exchange, allowing them to take advantage of hour-to-hour spot prices. • Enter into "contracts for differences" (hedging contracts to protect customers from wide price swings). These contracts will probably not be regulated by FERC or state public regulators. They are pure financial hedges, which could be entered into today if there were a solid basis for writing them. • Enter into bilateral contracts with generators or independent power producers. Stranded costs. Under the traditional regulatory system, utilities made commitments to generation investments and to long-term contracts with qualified facilities, which are not currently economic. It is widely agreed that the low spot market prices and excess demand that now typify the markets mean that utilities cannot recover their full long-term investments simply through spot market pricing revenues. The deficiencies are "stranded" costs. Many utilities view the issue as a matter of contract; the traditional contract with society, in return for an obligation to serve,

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involved a promise that these investments would be recovered (subject to reviews of the prudence of those investments). Stranded costs fall into several categories: contracts with qualified facilities, utility-owned generation, regulatory commitments such as deferred taxes and nuclear decommissioning charges, and public purpose programs such as demand-side management, low income rate assistance programs, and perhaps also resource diversity programs. Figure 1 puts the issue in economic perspective by looking at trends in utilities' embedded costs and market prices. In the 1970s, market prices (estimated by using utilities' marginal costs as a proxy) were generally above embedded costs, largely owing to high fossil fuel prices. Then, in the mid-1980s, market prices fell below embedded costs, as fossil fuel prices collapsed and utilities made substantial commitments to new resources, including nuclear plants and new contracts with qualified facilities.

Figure 1. The potential for stranded costs is the result of shifting economic relations hips.

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The Southern California Edison Company believes that, because utilities gave customers the benefits of embedded cost rates (through cost-of-service rates) when market prices would have been higher, they deserve the reciprocal treatment going forward: recovery of prudently incurred embedded costs, even though they may not be recoverable at current market prices. It is simply a difference between a long-term contract and a spot market contract. The long-term contract between utilities and society should be honored. The Competition Transition Charge (CTC), through which stranded costs are expected to be recovered, is not an added customer cost. These costs are already reflected in rates. The CTC will be collected in California subject to no cost shifting through a nonbypassable charge. The plan is to show it as a line item on customers' bills. Rates will be capped at their level of January 1, 1996, so that recovery of stranded costs will not boost rates. Collection is to be completed by 2005, except for stranded costs related to qualified facilities, which will be collected over the lifetimes of the projects (which often extend for some time). A hybrid method is being adopted in California for calculating stranded costs. The market valuation of each asset will be determined either by selling the asset or by obtaining an independent appraisal. Utilities will have five years in which to bring their fossil fuel resources to market and undergo market evaluation. Meanwhile, stranded costs will be calculated based on the difference between embedded costs and market prices during that period. When the utilities move to market valuation, the value of each resource will be assessed. That value will be compared with the book value of the resource, and the difference will be the stranded cost, which will be amortized over a period that cannot go beyond 2005. Roles of utilities after restructuring. Utilities after restructuring will still provide distribution service. They will own the transmission system, but it will be under the control of the Independent System Operator. They will engage in retailing, with tariffs based on the time-weighted average exchange price, a realtime price. There may be other tariff options that will also persist. Utilities will continue to own some generation, but will divest themselves of much of their generation. Nuclear and hydroelectric plants will apparently be retained by the utilities, at least for a time. Some of the

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fossil-fueled generation will probably be moved over to unregulated subsidiaries of utilities. Public purpose programs that are today funded in rates include low income assistance, women/minority/disabled veterans enterprises, renewable generation; environmental protection; local economic development; customer energy efficiency; and research and development. Some nonbypassable charge would be needed to continue funding such programs. Customers can expect to receive bills with many line items on them. There will be a separate supply charge, generally reflecting generation costs, and a separate wires charge for transmission and distribution. There will probably be a continuing public goods charge. For a time there will be also a Competition Transition Charge. CONCLUSION The Southern California Edison Company is prepared to compete for customers' business in this new environment. It certainly wants to remain the provider of power for the federal government and other large customers.

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COMPETITION IN THE ELECTRIC POWER INDUSTRY: A VIEW FROM NEW YORK

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COMPETITION IN THE ELECTRIC POWER INDUSTRY: A VIEW FROM NEW YORK Ross Hemphill Niagara Mohawk Power Corporation

I will address several topics regarding the restructuring of the electric industry to introduce competition in the state of New York. These will include the so-called "price problem" in New York; the multiyear rate case process; Niagara Mohawk's Power Choice Proposal; and other proposals under consideration. THE "PRICE PROBLEM" IN NEW YORK Electric power prices in New York are among the highest in the nation for both industrial and residential customers. Figure 1 is a map showing the average price paid by industrial customers in each state, using data from Edison Electric Institute reports. Industrial customers in New York are paying significantly higher prices, on average, than those in most other parts of the country. This has not always been the case; these prices have increased significantly over the past decade. The problem manifests itself in the price of electricity, but price is not really the problem; it is a symptom of the problem. The problem can be traced to an outdated system of regulation and an industry in need of restructuring. The two largest contributors to the growth in prices since 1990 at Niagara Mohawk are (a) requirements to purchase power from independent power producers (IPP) at above market prices and (b) increases in state and local taxes. Between them, these two items will account for more than half of Niagara Mohawk's costs in 1996, which is to say that more than half of the company's costs are outside our control. Figure 2

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Figure 1. Average revenue for electric utilities in cents per kilowatt hour: industrial class.

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Figure 2. Allocation of electric revenue for the Niagara Mohawk Power Corporation .

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shows that the IPP costs are increasing much more rapidly than any other costs. Niagara Mohawk also built two nuclear power plants, of course, but their costs are decreasing and will be less of a problem as the years go by, while IPP payments continue to rise. While there is, strictly speaking, no retail competition in the electricity business, the price problem presents real challenges to the company already. Self-generation, for example, is financially attractive to many industrial customers when compared to our full retail tariff, and a growing number of customers are considering it. Relocation of companies is another challenge. A number of customers say they are moving to other regions for lower priced power. We also face competition for residential and commercial customers; efforts to form municipal utilities are underway all over New York. To confront some of these challenges, Niagara Mohawk, about a year and a half ago, filed what is probably the most flexible tariff in the nation. It is a tariff that allows Niagara Mohawk the flexibility to sign contracts with pricing terms much different from the standard rates under which customers normally purchase electricity. The state regulatory commission requires justification of any such discounts on the basis of the customers' competitive alternatives. It is not a trivial task to make that determination. These case-by-case reviews are not practical in the long run. A more systematic solution is needed. NIAGARA MOHAWK'S 1994 MULTIYEAR PRICE CAP PROPOSAL Niagara Mohawk took the first step in that direction in February 1994, when it filed a multiyear rate case in which it asked for a price cap and indexing mechanism (something almost unheard of in the industry at the time). This multiyear proposal is still being negotiated more than two years later. The proposal included indexing of prices to the consumer price index over five years. The initial year was to be established using traditional cost-of-service ratemaking, which would have resulted in a fairly large rate increase in the first year. The proposal went nowhere, owing to opposition from the Public Service Commission staff, customer groups, and other interested parties. All parties had problems with the initial year's increase and most of the parties disliked the indexing plan. Industrial customers wanted assured

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reductions and were not satisfied with the proposal, under which Niagara Mohawk could reduce prices but was not required to reduce them. Advocates for residential customers saw too much flexibility in the plan, seeing it as a plan to impose greater than average price increases on their constituencies. Environmental advocates liked the idea of a multiyear price plan, but wanted something more conducive to conservation; they see price caps as providing too much incentive for sales growth. As a result, the commission bifurcated the case, dividing the proposal between the initial year (1995) and the subsequent years (1996-99). It directed the parties to negotiate a solution. From this directive came Niagara Mohawk's Power Choice proposal. THE POWER CHOICE PROPOSAL In October 1995, as a result of these negotiations, Niagara Mohawk released its Power Choice proposal, which has 10 elements: 1. Financial separation of generation from the rest of the Niagara Mohawk Power Corporation. The generation company would include all generating assets and remaining contracts with independent power producers. The remainder (transmission, distribution, and gas operations) would operate as a regulated utility, in a holding company. 2. A competitive wholesale generation market. An independent system operator also known as a ''Poolco" would administer the competitive wholesale market using real-time location-based marginal cost pricing. This pricing allows the creation of an efficient spot market taking into account constraints in the transmission system. 3. Customer choice of generation suppliers. Retail competition would be phased in within three years after the independent system operator and power exchange are operational, (and would ultimately include residential customers by the year 2000). Customers would pay the full costs of the necessary metering and communications technology for hourly pricing, and for stranded costs remaining after contributions by Niagara Mohawk and independent power producers (see items 5 and 6 below).

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4.

5.

6.

7.

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Purchases would be made either through an independent system operator or through bilateral contracts. Freezing prices through the year 2000. In the current structure, continued cost-based regulations would require price increases of more than 4 percent for 1996 and 1997. The Power Choice proposal would impose a price freeze for all customers from 1996 through 2000, except industrial customers, who would see price decreases of 10 to 12 percent. On February 12, 1996, Niagara Mohawk filed for temporary rate relief. We also filed a full revenue requirement rate case for rates effective January 1, 1997. These actions were taken to protect the interests of our shareholders. Funding the price freeze. The $2 billion cost of the price freeze would be shared by Niagara Mohawk ($400 million) and independent power producers ($1.6 billion), in proportion to the parties' shares of the stranded costs of generating units. Recovery of stranded costs from independent power producer contracts with advance-payment accounts. One of the most onerous types of independent power producer contracts, advancepayment contracts, required Niagara Mohawk to pay in advance, to help independent power producers obtain financing. The contracts require independent power producers to repay the amount they have been overpaid relative to avoided costs; since avoided costs have fallen, the amount owed is substantial. Under current state and federal law, the New York Public Service Commission has the authority to order such independent power producers to obtain commercial acceptable firm security for these obligations, which would save Niagara Mohawk customers about $1 billion (net present value). Recovery of the remaining strandable costs resulting from restructuring independent power producer contracts. Opening generation to competition in 1997 would produce about $5 billion in stranded costs (net present value) if no provisions for recovery were made. An absolute condition on the proposal is that any strandable

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costs remaining after cost reduction would be fully recoverable by Niagara Mohawk and the independent power producers through access charges for the remaining monopoly services. 8. Restructuring contracts with independent power producers. To ensure adequate numbers of generation competitors and to improve the efficiency of the market, some or all of the independent power producers must sell into that market or directly to customers as retail access is phased in. Niagara Mohawk prefers to negotiate, but it is prepared to restructure contracts through its power of eminent domain. 9. Additional state action. The relevant state agencies are requested to take a variety of actions. The Public Service Commission would approve the proposal, including the use of condemnation by Niagara Mohawk in restructuring independent power producer contracts; issue an order requiring firm security from independent power producers with advance payment accounts; eliminate regulatory micromanagement; eliminate or reduce public purpose programs that cannot be supported by the market (such as subsidized demand-side management); and ensure a level playing field for Niagara Mohawk and its successors. The New York Power Authority would refrain from shifting strandable costs to residential customers through subsidized industrial rates; would take steps to make condemnation possible; and would assume financial responsibility for nuclear units. 10. Formation of a holding company. Unregulated affiliates formed to offer generation and other services would be housed in a new holding company. THE NECESSITY OF RECOVERING STRANDABLE COSTS During the past two years Niagara Mohawk has identified ways to decrease its costs in many ways. As mentioned earlier, the cost of its own generation has declined significantly. The company has also reduced its work force by 28 percent since 1994. However, because of the reasons

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stated earlier, it still has costs that will not be recoverable in a competitive market. The show-stopper in this plan is the question of strandable costs resulting from the restructuring. The utilities will ultimately recover their strandable costs. The question is whether the country will face years of litigation before that fact is established. If customer advocates and commissioners take stands against appropriate recovery of these costs, they will slow the process of restructuring immensely. The independent power producers are no different in that respect from the regulated utilities. They received long-term contracts for their power. On the basis of those assured revenue streams, their shareholders and bondholders invested. Faced with losing that revenue stream, they will litigate. UNBUNDLED SERVICES AND THE TRANSITION FEE An important part of the process of unbundling services offered, and the prices paid for them, is what we call the competitive transition fee. (In California they call it the Competition Transition Charge.) Customers will see it as a line item on their bills. Over time, depending on the terms of the arrangement, it will be phased out, and generation will be a fully competitive market. Customer service, distribution, and transmission will continue generally to be offered by a franchised utility on a monopoly basis, although some customer services might become competitive in the future. The process of unbundling services requires assigning the transition fee to the various customer classes and the various services. How this is done will certainly vary depending on what state your business is in. The Niagara Mohawk Power Choice proposal is designed to allocate the transition fee to customers in a manner that has relatively little effect on the total bill that was being paid under full-service regulation. In other words, the transition fee is designed to keep the customer bill from rising or falling. OTHER PROPOSALS UNDER CONSIDERATION Two other serious proposals for utility restructuring are being considered. One is embodied in a bill from the New York General Assembly. The other is a recommended decision by the staff of the Public

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Service Commission. The two proposals have much in common with the Power Choice proposal, but each has some stark differences, which Niagara Mohawk sees as problematic. The point is that restructuring is inescapable, in New York as well as in California. CONCLUSION Electricity generation is no longer a natural monopoly. Functional unbundling, if not complete financial separation, is imminent. I believe retail competition in generation will become a reality much more quickly than many observers expect. Recovery of strandable costs is a requirement for retail competition. Complete recovery of strandable costs in the short-term—that is, over the phase-in period—will not significantly decrease prices but will not increase them. In the long-term, however, everyone will benefit from the restructuring. The electric utility industry is shifting from a monopoly mentality to a focus on markets. One speaker at a conference last year observed that the electric utility industry seems to experience eras. It started with a technical era, looking for technical efficiencies. Then it went through a financial era, in which power plants were built in great numbers and utilities strived to recover those investments. Now it is moving into a market era. The market era will provide many, many benefits for the customers. It is a very exciting time to be involved.

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BUYING AND SELLING ELECTRICITY: PERSPECTIVE OF A POWER MARKETER

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BUYING AND SELLING ELECTRICITY: PERSPECTIVE OF A POWER MARKETER Donald M. Black Enron Capital and Trade Resources

My company, Enron Power Marketing, is the nation's largest power marketer and its third largest wholesaler of electricity, behind the Tennessee Valley Authority and the Bonneville Power Administration. Enron is a company with $9.2 billion in revenues and assets of $13.2 billion. Enron's electric power marketing business and trading activity in electricity began in June 1994 and has developed quickly. Last year Enron bought and sold about 7.8 million megawatt-hours, and it is on pace to exceed that amount in 1996. At this pace of growth, Enron could conceivably be the largest utility in the country in a few years. The wholesale market for electricity is about $90 billion annually. That makes electricity by far the nation's largest commodity business. By comparison, the natural gas market is around $30 billion. Even more impressive is the retail market for electricity, which is in excess of $200 billion. There is a tremendous amount of money at stake here. Enron is in the business of structuring long-term custom energy contracts designed to lower customers' costs. Enron trades natural gas, gas liquids, and now electricity as commodities. Our trading activity is conducted on a trading floor that is very similar in appearance to a typical securities trading floor on Wall Street. Our hourly traders deal in the real-time market, buying and selling the commodity hour-to-hour and day-to-day. Mid-market traders focus on transactions and opportunities within the next year, such as selling into scheduled outages of generating units or arranging seasonal exchanges between utilities in different parts of the country. Long-term marketers, of which I am one, focus on longer term,

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more sophisticated transactions. These professionals include power marketers, gas marketers, an independent power producer (IPP) group (New York and California are two of our favorite locations for IPP activity), and an industrial services group which concentrates on the energy requirements of key industries in the United States, such as metals, paper, and petrochemicals. Enron is also very active in finance and currently has more than $1 billion in loans and other financial assets closed. Recently we started looking at financing activities including equity positions in end-user companies (i.e. retail load) to supplement activities in power and gas contracts. Enron is a power marketer, not a power broker. Unlike a broker, it takes title to the commodities it sells. Its profit is the difference between the bid (to buy) and the offer (to sell). Brokers, on the other hand, arrange transactions, matching buyers with sellers and taking fees without taking positions. Enron's business entails entering into and managing risk positions. A broker takes no risk. INFORMATION AND COMMODITY MARKETS Enron is a commodity dealer, trading in electricity and natural gas and managing the risks of doing so. Information is the vital element of any commodity business, and whatever entity can accumulate the most information and act on it most quickly will have a competitive advantage. The trading floor is designed to let Enron's professional traders assimilate and act on information quickly. At any moment, they know exactly where power prices are trading throughout the country. Enron's traders also monitor moment-to-moment wheeling costs and availability and the locations of bottlenecks in the transmission system, so they can take advantage of arbitrage opportunities as they occur and generate market liquidity. The market for energy is developing to the point that power follows price signals, and Enron believes that at some price it will always be able to buy the necessary capacity and energy to meet its requirements. THE QUESTION OF RELIABILITY Enron's lack of a reliability track record is one issue I face routinely as I pursue business. We have been in this business less than two years; most of the competition has been in the business far longer. When

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one of our counterparts enters into a contract with Enron, they are assuming the risk of whether Enron will be there to meet its obligations during the term of that contract. Why, then, do energy users buy from Enron rather than their traditional utilities, which have been in existence for decades? One reason is that Enron has been in the natural gas business for more than 10 years, with an excellent record. Second, it has been absolutely reliable as a power supplier over our two years of power marketing activity. Most important, perhaps, is the fact that there is no longer any guarantee that the traditional local utility supplier (Enron's competition) will be in business over the term of any contract they may sign either. Every single utility is transforming itself, and many are trying to operate the way Enron does. Finally, nearly every U.S. utility trades with Enron. They are beginning to recognize us as a reliable source, so why should other customers not? TIMING IS EVERYTHING Timing is everything in commodity markets. I believe now is a good time to enter into long-term contracts for power. The American power market is in oversupply in relation to demand, partly because the franchised utilities have built an infrastructure that was designed to be 100 percent reliable. As a competitive market for capacity and energy evolves and the distinctions between utility service territories begin to blur, that infrastructure begins to overlap between utilities and become redundant. With open access to the nation's transmission grid now guaranteed through the Federal Energy Regulatory Commission's (FERC) Notice of Proposed Rulemaking, power can now go anywhere, and the transmission necessary to wheel power must be made available. As a result, the spot market is trading on a marginal cost basis. Power marketers and other market driven participants can offer contracts for far less than it would cost to build generating capacity. Over time, we know the imbalance will correct itself, in part because little new capacity is being built. However, we do believe most of the capacity that will be built in the next decade will probably be natural gas-fired plants located near load centers. The spot market for power is becoming increasingly liquid. Out of the liquid spot market will come a more liquid longer term market. Therefore, I believe that buyers have an opportunity over the next two years or so to take advantage of long-term contracts for portions of their

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requirements. I don't suggest that customers "bet the farm," but instead that they would be wise to think of their power supplies as a portfolio, with some longterm, some mid-term, and some short-term positions. The largest market for long-term wholesale deals is the nation's municipal systems. Enron is pursuing this market aggressively. So are the investor-owned utilities, which have spent the past year or more trying to arrange long-term contracts with these wholesale loads. The utilities know they must shore up their customer bases as they reengineer their companies in preparation for deregulation. But the utilities still have trouble binding themselves to 10-year fixed price contracts. So far I have seen the utilities offer fixed prices for 3 to 5 years, but thereafter prices typically float according to an index of fuel costs or other standards. Enron today offers fixed-price contracts out to 20 years for baseload, intermediate load, and peaking firm energy and/or capacity, along with a variety of ancillary services that will become available as the transmissionowning utilities file their tariffs for unbundled services. As retail competition in the power markets becomes a reality, these same evolving markets will allow the formation of service companies that aggregate load and provide power for retail customers. Such a firm could hire a few traders to buy, in real-time, the cheapest energy available from moment-to-moment. In that way, a household could take advantage of spot prices from whomever is selling at the lowest price at the time. As the spot market continues to develop and market indexes are created, an active financial (not physical) market will arise. That market will help buyers and sellers hedge their risks without having to purchase the actual commodity. With indices, power marketers will be able to set caps on a buyer's energy prices, permitting a buyer, for example, to deal in the spot market until the price reached a preestablished cap. Or an energy user could sell a power marketer a floor on prices, so the price would float until it reached the floor. On an energy user could buy a collar, which allows the price to float within an interval. The variety of such products is limited only by the demand for risk. THE OGLETHORPE EXAMPLE Enron has arranged a contract with Oglethorpe Power Corporation in Georgia under which Enron meets Oglethorpe's entire load, at a fixed price that is lower than Oglethorpe would have otherwise charged itself.

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Enron is dispatching the system according to the momentary market price, running Oglethorpe's generating units only until the market price is cheaper and then buying from the market. In essence, Oglethorpe has hired Enron to run their system, and appears to be very pleased with the results. CONCLUSION Unfortunately, federal agencies cannot yet take advantage of these opportunities. Section 8093 of the 1988 Department of Defense Appropriations Act, in essence, forbids federal installations from buying power against state laws that typically set franchise rights for utilities. Tremendous savings would be available to the agencies, and ultimately the taxpayer, if this barrier were lifted. In general, I warn you to beware of delaying tactics designed to slow the opening up of power markets to competition. One potential argument for delay is the need to conduct adequate technical assessments on the impacts of deregulation. Technical assessment is appropriate, but if assessment is used as a veiled delaying tactic to give utilities a chance to shore up their balance sheets and prepare themselves to compete, then it is not in consumers' interest. Again, timing is everything, and the time to move is now.

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PERSPECTIVE OF AN ELECTRICAL POWER CUSTOMER

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PERSPECTIVE OF AN ELECTRICAL POWER CUSTOMER

Jim Clarkson Heath Petra Resources Company

Full-fledged competition and the ability to buy on the wholesale market may be a few years away, but large power purchasers already have more options than they had in the past. Utilities, as competition approaches, are eager to make deals and are trying to become more responsive to their big users. From the customers' standpoint, now is the time to press the advantage. MARGINAL COSTS AND THE PRICE OF POWER About 44 percent of the power generated in the United States goes through the bulk wholesale markets before reaching the retail customer, so there is an active, well-established trading mechanism already. Any problems that might have existed with utilities' swapping power have already been worked out. The commercial arrangements are also well developed. The prices at which these trades are made are sometimes startlingly low, as low as $3 per megawatt hour (0.3 cents per kilowatt hour). Yet the generators make the sales because they contribute to the variable costs of running the company. Similarly, a manufacturing company producing widgets at a break even price of $1.00 will keep selling widgets at a price of, say, $0.60 if it can make the units for $0.50 in variable cost. In both cases the costs are divided between fixed costs, which are amortized over time, and variable costs to make the unit. The sales cover the variable costs and contribute to the recovery of fixed costs.

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This phenomenon is known throughout the rest of the economy, but not to the utility industry. In the competitive sector of the power industry, prices are down near the variable costs of the utilities. Those prices represent short-term bargains, which would be akin to the widget manufacturer trying to eliminate its inventory and selling widgets for $0.25. In the West particularly, unusually high rainfall in 1995 filled up the hydroelectric reservoirs, and power is being given away at very low prices. In addition, some nuclear plants can make electricity at costs below 1 cent per kilowatt-hour, and the owners have been unable to sell all of that power until recently. Prices are below what one would expect. In an economy with overcapacity, one would expect that, as the need for power increases, the generation resources with the next highest variable cost will be called on at each step. If the amount of power needed required all of the generating plants available—all the way up to the ones costing 18 mils or 1.8 cents per kilowatt-hour to make power—then that would be the price for everyone, even for hydroelectric plants, which cost virtually nothing to run. That is the way our market works. It is a new experience for the utilities, who have never experienced periods in which they were not collecting on their fixed costs. Their fixed costs are having to be deferred unless they can get their variable costs below the marginal cost of bringing on the next unit. LOW-COST POWER: A PREDICTION Retail electricity prices today vary widely from utility to utility in this country, between 3 and 5 cents per kilowatt-hour, and more in some places. The fully loaded costs in the competitive wholesale market are much less than that. Resources in the range of 0.3 to 0.9 cents per kilowatt hour are not going to be available for long, but in the future, supply and demand will stabilize at a price of about 1.5 to 2 cents. The retail market, when it is in place, will go to those same prices, and there will be less variation, because fixed costs (which led to much of the variation) will not come into play in setting prices. The utilities, in selling power, need to receive, say, 2 cents to cover their variable costs. They are also collecting capital costs in the form of demand charges of, say, $10 or $12 per month. But they will forego recovery of capital costs in a competitive market, so the price of power will be about the same to

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customers with low load factors, such as residential customers, as it is for industrial customers. The large difference in prices to the two classes of customers today is due to the way fixed costs are allocated over the units sold. A big user using many units on a steady basis has the fixed costs spread over more units, so the average cost is perhaps 3 to 4 cents, while a residential customer, with a worse load factor, might be charged 7 or 8 cents. In a competitive market no one collects the fixed costs, and the variable costs apply to everyone, so price variation is smaller. A BOOM IN ELECTRICITY-INTENSIVE INDUSTRY This low-cost power will create a boom in certain industries. Some of America's electricity-intensive industry will come back to the United States, at least into the areas that first implement competition. The aluminum industry is an example. For 20 years the conventional wisdom held that one cannot build an aluminum plant in the United States, because of the high electricity costs. About a year ago I was involved in assessing a U.S. aluminum company's plans to build a smelter in Malaysia. An aluminum smelter needs a huge amount of power, so a power plant was going to have to be built, in this case a plant fired by low-grade coal. The capital cost was estimated at $800 per kilowatt, and coal was expected to cost about $15 to $17 per ton. In all, it came to about 28 mils, or 2.8 cents, per kilowatt-hour for power. Now the company appears to have abandoned that plan, and is considering expanding in the United States, because of the prospect of power selling for 1.5 to 2 cents per kilowatt-hour. The United States, in other words, has a competitive advantage in electricity prices. Elsewhere in the world, if one intends to build a facility with a large power load, one must build one's own power plant. The United States has about 20 percent excess power, and power needs here are growing at about 2 percent per year. As a result, we can expect fire-sale prices for electricity for a number of years. There is more good news. In a few years, when excess power is used up and the utilities can begin raising prices, due to developing shortages, they will find that technology has placed a ceiling on prices. That ceiling is due to the technology of combined-cycle generation (a natural-gas fired turbine, with waste heat recovered to power a steam turbine). The cost of these highly efficient systems has fallen dramatically in the past few years, and continues to drop. One can expect electricity from combined-

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cycle plants to be priced at 2.4 to 2.8 cents per kilowatt-hour. With the marginal cost of electricity at that level, future prices should not rise to the levels of regulated retail prices in the past. CUSTOMERS' STRATEGIES FOR LOWERING POWER COSTS Meanwhile customers can use interruptible power to keep power costs lower. That is, they can agree to interrupt their power at signals from their utilities (for example, at times of peak load) in return for lower rates. Customers can cut off some of their equipment or use local generators to make up for the interrupted power. In effect, the utilities in these arrangements are giving customers power at its energy cost, without collecting demand charges. Many utilities also offer customers so-called real-time pricing. In these arrangements, the price rises and falls to reflect the actual cost of power at the moment. Customers receive strong cost signals, and can schedule their energy use to take advantage of low-cost resources (such as in off-peak hours). For the first time there is feedback between suppliers and users. Users have an opportunity to control their own costs. Utilities can communicate in the strongest possible terms the cost of starting up that last peak load power plant, and can even influence customers consumption enough to avoid adding new peaking capacity altogether. In practice, however, many utilities have used real-time pricing as a means of adding to their revenue without adding plants. The price signals in such cases are artificially high, reflecting not the cost of power on the grid, but the utilities' desire for revenue. Niagara Mohawk and a few others have developed revenueneutral real-time pricing tariffs. Still, if a utility offers real-time pricing, customers should examine the option; these time-of-day premiums are negotiable as to exactly the sort of premium that is to be added to the overall price. Furthermore, even if the price spikes are artificially high, customers can work around them enough to lower their overall power costs. Such activity can result in enormously profitable paybacks.

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OPPORTUNITIES AND RISKS IN ELECTRIC COMPETITION: A VIEW FROM THE DEPARTMENT OF DEFENSE

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OPPORTUNITIES AND RISKS IN ELECTRIC COMPETITION: A VIEW FROM THE DEPARTMENT OF DEFENSE Millard Carr Office of the Assistant Secretary of Defense for Economic Security

The Department of Defense (DoD) has responded to the electric utility deregulation process by trying to achieve consensus on what the Department expects and wants from the process. Historically, often the Defense agencies' relations with public utilities have naturally been adversarial. The agencies' objective in rate negotiations has been equity: rates that reflected the true cost of service. Sometimes they were successful and sometimes not, depending on whether the state public utility commissions were predisposed to subsidize one rate class or another. Today's changing circumstances demand a new relationship with power suppliers, including the following: • The ability to take advantage of competition for supply and the economic benefits that result from it. • The ability to reduce utility costs, increase energy use efficiency, and improve the power infrastructure (which has been neglected since the Second World War). • Access to the value-added services of public utility companies and of nonutility suppliers of power and associated services, such as demandside management, utility system operations and maintenance, highvoltage maintenance, and environmental programs, at no cost or the most favorable rate. • Customer assistance in obtaining the lowest cost rate and service availability, such as time-of-use rates.

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My office has been working with the Edison Electric Institute (an industry group representing electric utilities) and others to develop a partnership to minimize financial risk for both parties and accomplish all mutually beneficial projects. An acceptable model contracting process for the upcoming period of transition is one of the projects we are working on with the utility industry. But every situation is unique, so there must be room for local innovation. Each military base is different from every other base. Bases are like small cities, containing thousands of buildings with a wide range of uses, some dating from as early as the War of 1812. These bases have complicated power distribution systems, which are deteriorating. The Department's goals are an appropriate level of competition, objectivity, savings validation, and resource optimization. Its dream, which may be unobtainable, is energy-source-neutral, life-cycle-costeffective decisions on the use of taxpayers' funds in a businesslike way. One general obstacle to achieving those goals, and that dream, is an institutional culture of risk-aversion. No one, at any level in the federal government, has the incentive to take risks or try something different. Those who take risks and fail suffer; those who succeed are generally ignored. The National Performance Review and the initiatives coming from it are helping to change that culture, but the change is slow. REPORT TO CONGRESS The Department of Defense submitted a report to Congress on March 27, 1996, on ways to buy electricity at the lowest cost, identify regulatory or legal impediments to achieving lowest cost, and identify changes in legislation that would be needed to achieve cost savings. The report, ''Procurement of Electricity from the Most Economical Source," was prepared in response to a provision in a 1995 House bill (section 357 of H.R. 1530), which did not become law, but would have required the Department to buy electricity from the most costeffective source. The report pointed out that Congress had passed a law in 1988 (section 8093 of the 1988 Department of Defense Appropriations Act [Public Law 100-202]) that forbids competition, by requiring Defense facilities to buy electricity according to state regulatory requirements (that is, from local utility companies). Under that law it is impossible to generate competition for electricity purchases as we do for all other commodities.

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Beyond rate negotiations with utility companies, there is no mechanism for buying electricity from more cost-effective sources. The report identified corrective measures that could be taken. Repeal of the 1988 law is one obvious option. By itself, however, repeal would have a limited effect, because Defense Department facilities are retail, not wholesale, customers, and only wholesale customers are eligible for competition under the Energy Policy Act of 1992. Utilities have little incentive to provide Defense installations access to the transmission grid to buy electricity from generators that sell at lower prices. One way to overcome that barrier, the report suggests, would be to define Defense facilities as "eligible customers" under section 211 of the Federal Power Act. The Federal Energy Regulatory Commission (FERC) is authorized to determine whether those facilities could take wholesale power. It would be possible to place military installations in the same class as municipalities, other utility companies, and cooperatives. That decision would allow DoD to enter the market for wholesale power. These measures, the report estimates, would together save $30 to $70 million annually at the 40 bases that have electricity bills of more than $5 million per year. That estimate does not include any stranded costs that would have to be repaid. Nor does it include transmission charges, access fees, or any costs for social programs that have been supported by utility costs. So the savings in reality are probably less than that estimate. On the other hand, the savings could be higher, because the estimate did not include many smaller bases that could be given access to this market if Congress desired. The report also suggested that the only way to determine the benefit to the Department of Defense and the taxpayers is by testing competitive purchases on a small scale first. The report added that the Administration, as represented by the Office of Management and Budget and the Office of the President, is opposed to mandatory retail wheeling and is concerned for possible undesired societal consequences. FOCUSING ON THE BASICS For the Department of Defense, mission support is the most basic objective, and the highest priority by far. However we procure electricity in the future, we must ensure that mission support is not harmed. Immediately below mission support are the quality of life and productivity

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of defense personnel. If the facilities save large amounts of money on energy, but the quality of energy support or continuity of service deteriorate, it could degrade productivity. The losses in that case would be far greater than any energy savings. The Department must also focus on achieving the lowest life-cycle costs, not the lowest immediate costs. Short-term optimization over the past 50 years is the reason that the infrastructure of military bases is so deteriorated. This effort to save on energy costs should not be allowed to take that course. The Department also needs flexibility for the future. It is difficult to predict what will happen in the next 5 or 10 years. The Department must not lock itself into programs that prevent it from taking advantage of changes in technology or changes in political or business philosophy. It is critical also to be alert to unintended consequences. The Department of Defense is focusing on its interest as a customer, but there are other broader national interests that the government of the United States must take into consideration. CONCLUSION Development of policy in this area continues. An interagency study group is being orchestrated by the Office of Management and Budget. The Department of Defense is working with the Edison Electric Institute in many different ways to smooth the path toward a market-oriented future. The Department is also working with others that want to provide services and products that utility companies have traditionally provided. In general, it is trying to maximize the net benefits to society as competition begins to pervade the electricity industry.

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SAVING BILLIONS FROM ENERGY EFFICIENCY IN THE FEDERAL SECTOR: INSTITUTIONALIZING ENERGY EFFICIENCY IN FACILITY MANAGEMENT

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SAVING BILLIONS FROM ENERGY EFFICIENCY IN THE FEDERAL SECTOR: INSTITUTIONALIZING ENERGY EFFICIENCY IN FACILITY MANAGEMENT Mark Ginsberg Federal Energy Management Program

The federal government has set itself ambitious goals for energy efficiency. The Energy Policy Act of 1992 and a series of Presidential executive orders have established the goal of reducing energy consumption about 30 percent below the 1985 consumption by the year 2005. Because the federal government spends about $8 billion each year on energy purchases to operate its 500,000 buildings (3.2 billion square feet of space), power its vehicles, and perform its mission, energy savings are an important way to reduce the cost of government. The federal government is, in fact, the largest energy consumer in the country, using more energy than the entire state of Alabama. The Federal Energy Management Program has the task of leading this continuing effort. It goes straight to the bottom line of deficit reduction. Since 1985 energy efficiency measures have saved the government $9 billion, enough to provide the annual energy needs of the state of Vermont. Energy efficiency measures will save more money than all of the base closures (and without the negative economic impacts of base closures). The efficiency gains to date, if we considered the government as an enterprise, would have paid for the investments needed to make those efficiency improvements and would pay for all of the other projects needed to reach the 30 percent savings goal. It gives us free pollution prevention along the way, and by 2015 it will have given the federal government a net "profit" of over $15 billion.

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OVERCOMING BARRIERS TO ENERGY EFFICIENCY If the gains are so obvious, why is it not happening more quickly and more easily? There are some barriers of institutional policy, of procurement, of information, and of funding. Institutional and policy barriers. Agencies tend to focus on their primary missions. But if efficient delivery of services is seen as integral to our missions, then energy efficiency is fundamental to every agency's mission. Everyone who manages facilities should place a high priority on energy efficiency. In particular, the tendency to concentrate on initial costs rather than life-cycle costs, (which is a matter of federal policy, but rarely used) should be combatted. The temptation is to build a cheaper building-reducing insulation, buying cheaper air conditioners and so forth. The truth is that energy efficiency does not have to cost more initially, and wasteful energy systems will cost far more in the long run. We are trying to increase awareness of the benefits of life-cycle costing. Investments in energy efficiency pay large returns over the lifetimes of facilities and systems. Other institutional barriers exist. There are stories of agencies, being unable to accept utility rebates owing to accounting problems. FEMP can help in such cases. For example, FEMP helped the Department of Veterans Affairs obtain incentives of $500,000 in Fort Worth for ice thermal storage and more than $1 million in Los Angeles for demand-side reduction measures. FEMP has working groups and other methods for overcoming institutional barriers. Procurement barriers. The federal procurement system, as is well known, has many barriers embedded in it. In general, it stresses competition and equal access, in a complex process to prevent abuse. It also makes innovation difficult. Streamlining the procurement system is a high priority today. The federal government, with the help of the Federal Energy Management Program, has taken action to put government procurement in the service of energy efficiency. The Energy Policy Act of 1992 and Executive Order 12902 require federal agencies to purchase products that are at the upper end of energy efficiency, in fact the top 25 percent. It is not easy, however, to know which products meet that goal. Life-cycle cost analysis is one way to make such determinations, but not all products list

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their energy efficiency ratings. So FEMP is preparing technical reports on product guides on 35 technologies to help guide federal facility managers and purchasing agents. Twenty-two agencies have signed pledges to buy in the upper 25 percent as part of a Federal Energy and Resource Conservation Procurement Challenge. The major military and civilian purchasing agencies are considering identifying qualified products in their catalogs. These initiatives have substantial effects on the market. The federal government spends $20 billion a year on energy-consuming products, $8 billion just on office equipment. When it sends a signal to industry that it wants to buy in the upper 25 percent of the market in energy efficiency, industry recognizes that desire as the basis of a receptive market, and will produce products for it. For example, a few years ago the General Services Administration, the Environmental Protection Agency, and the Department of Energy announced that they wanted to buy in the upper end of the energy efficiency market for desktop computers. Now we have Energy Star computers that use less energy than desktop computers did previously. The Federal Energy Management Program also offers leadership for those outside the federal government. For example, FEMP is actively supporting a state collaborative lead by the New York State Energy Research and Development Authority, to expand the pool of governments buying energy-efficient products and multiply the public sector procurement clout. As a direct result, prices of these products should go down for everyone as volume sales grow. Information barriers. Information barriers are the products of rapid advances in technology. There are so many products and competing claims that it is often difficult for federal energy managers to make informed decisions. Lighting technologies are advancing so quickly, for example, that it is probably cost-effective to invest in new lighting systems even if they were replaced with high-efficiency units only five years ago. Today's motors are highly efficient, and replacing chillers (required in any case for environmental reasons) generally results in improved efficiency. The technologies are advancing so rapidly that it is hard to keep track of the state of the art. The Federal Energy Management Program provides direct technical assistance, on-site audits, training, a variety of new technology

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demonstrations, "showcases," and the tools federal facilities need to get the job done. Funding barriers. Declining appropriations are placing heavy pressure on the funds available for investments in energy efficiency. The appropriations for energy efficiency investments have declined from more than $250 million in fiscal 1995 to about $75 million in 1996. As appropriations go down, it becomes necessary to seek other sources of energy savings. One of those sources is energy savings performance contracting. Another is utility incentives. Energy savings performance contracts are required by the Energy Policy Act. As competition takes hold in the electricity industry, the federal government can take advantage of that competition as energy service companies offer to provide many of the services that utilities have provided in the past. Rules and procedures in place as a result of the Energy Policy Act are available to agencies to help them use energy savings performance contracts. The Federal Energy Management Program also works with utilities, the traditional suppliers of power, which want to retain some of their largest customers. A Federal Utility Partnership Group has met every few months for the past two years or so to look at utility incentives. The group includes representatives of three dozen of the largest utilities in the country, who are interested in working with the federal government. The evolving relationships with utilities have resulted in some successes: •

The General Services Administration and FEMP have explored streamlining the procurement of a broad range of services through areawide agreements that some utilities have with the government. A new hybrid approach is evolving. One example, the New Mexico Initiative, makes all federal facilities in the Public Service of New Mexico territory eligible for reimbursable project funding. • The Potomac Electric Power Company has given the Department of Energy headquarters an old-fashioned utility rebate combined with an energy savings performance contract. Combining the utility incentive and the energy savings performance contract, DOE was able to replace 30,000 fixtures, reducing the energy consumption of

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• •

•

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lighting by more than 63 percent. The government will save $340,000 over the life of that project in that one building alone, at no capital cost to the government. The Southern California Edison Company has provided more than $55 million in incentives to federal agencies in its service territory. Baltimore Gas and Electric has taken a hybrid approach. BGE has become part of the agency's qualified vendors list as an energy service company. But it is also a utility, providing the kinds of services available to all customers. San Diego Gas and Electric has not only applied energy efficiency measures, but has carried out some water conservation projects in its service territory. Consolidated Edison in New York, one of the largest utilities, has provided $10 million in incentives to federal agencies in its service territory. The U.S. Army at Fort Lewis and the Department of Energy's Battelle Pacific Northwest Laboratories studied how to reduce costs at the base, which is growing as other bases close. With the help of Tacoma Public Utilities, more than $20 million of infrastructure improvements were made at a cost to the Army of only $3 million. Public Service Company of New Mexico is one of the models of the new hybrid approach, a combination of utilities and energy savings performance contracts. The utility works with all of the agencies in its service territory—Kirtland Air Force Base, several large Department of Energy facilities, Sandia and Los Alamos National laboratories, and the Waste Isolation Pilot Project facility—and has offered to finance projects in its service territory. The opportunities to save energy at Kirtland alone would result in $7 million in energy savings and $500,000 in water conservation.

If one adds it up, there are billions of dollars of savings potential in our relationships with utilities and energy savings performance contracts. Is it easy to do? Unfortunately, it is not. For that reason, FEMP is working with the agencies on these projects. To spread the news about these

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opportunities, the Federal Energy Management Project uses video telecasts to more than 300 sites. CONCLUSION The technology and the economics of energy efficiency are well known. All it takes for federal facilities managers is the will to act. Champions are needed in the agencies. Each of these champions will have a friend and partner at the Department of Energy. Collectively, we can not only stimulate the private sector to produce more energy efficient products, not only reduce pollution, but also help save the government billions of dollars.

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ACQUISITION OF UTILITIES SERVICES: SOME LEGAL CONSIDERATIONS

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ACQUISITION OF UTILITIES SERVICES: SOME LEGAL CONSIDERATIONS Robert Kittel Department of the Army

If asked why they buy electric power on a sole source basis, most people who buy power for the Department of Defense (DoD) would say that the reason is section 8093 of the 1988 Department of Defense Appropriations Act. But that provision became effective only in 1988. For many years before that law was enacted, agencies has been procuring electricity from their local utilities on a sole source basis. DoD and other agencies have bought power on a sole source basis for a number of reasons. First, they often have been able to find no other supplier of power than the local franchised utilities. Arguably, because of the legal principle of federal supremacy, agencies could procure power from any source, regardless of state franchising laws. But there remained the problem of how to move the power the agency might purchase somewhere else to the necessary delivery point. So, wheeling is a problem separate and apart from the restrictions in section 8093. Second, there is an institutional problem. Sole source procurement, on the basis of a published tariff, is simply easier, Even if it were not easier, federal agencies today lack the necessary resources and expertise to procure power competitively. If they were authorized to procure power competitively today, few agencies would be ready to do so. A change in the law authorizing federal agencies to procure power competitively would simply create a legal basis for potential offerors to sue the agencies if they failed to do so. Thus, it is not as simple as merely changing the law. Agencies must provide the resources necessary for the procurement activities to conduct a competitive acquisition of power.

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The acquisition of local telecommunications services presents an example of this problem. The law has been changed to authorize the procurement of local telecommunications services on a competitive basis by all users. However, the military services are only beginning to address how they will move from a sole source to a competitive environment. Acquisition planning is just beginning. HOW TO ACHIEVE A COMPETITIVE SYSTEM In dealing with these issues, it is instructive to review the analysis of the report DoD recently submitted to Congress, as it was required to do so by last year's DoD Authorization Act (''Procurement of Electricity from the Most Economical Source"). In that report DoD was asked to comment on the means necessary for moving to competitive procurement of electricity. The report discussed two potential ways. First, Congress could repeal section 8093. However, DoD does not recommend that course of action alone, because it does not resolve the question of how to move the power purchased competitively to DoD installations. Second, Congress could repeal section 8093 and in addition provide that DoD activities are eligible customers for the purchase of wholesale power and, as such, subject to the jurisdiction of the Federal Energy Regulatory Commission. DoD agencies could compete in the FERC-regulated wholesale power market and move power to their installations under FERC rules on wheeling. It is this change that DoD recommended to Congress. However, authorization of this approach would not resolve the agency resource and expertise problems discussed above. There are no easy answers. I would urge, however, that agencies begin preparing now for this new emerging competitive marketplace. It will happen; perhaps in California first, or perhaps in another state. It appears inevitable, and federal acquisition offices should be planning their response. They need to plan what they intend to buy, whether to buy from one company only or from multiple companies, the lengths of the optimum contract periods, the transmission and distribution services that they will need, what will likely be available, and so forth. Will it be too difficult for federal agencies to make competitive power purchases with 50 different state public utility commissions setting the rules? Would it be better to receive wholesale eligible status under the

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Federal Power Act and worry only about FERC's rules and regulations? Efficiency would seem to argue for eliminating the multitude of rules and regulations that apply and simplifying contracting through wholesale status. EXISTING OPPORTUNITIES Clearly, today there are opportunities for federal agencies in the evolving competitive marketplace. Utilities have shown increasingly that they are worried about retaining federal agencies as customers. At the political level, they have an interest in working with federal agencies (as in the ongoing meetings between DoD and the Edison Electric Institute), to help maintain Congressional support for keeping section 8093 in place. Federal agencies can take advantage of this leverage. They should be seeking reduced rates, with the implied threat of the competitive marketplace. Utilities value highly the opportunity to secure large loads such as those of federal facilities. For example, recently the El Paso Electric Company (which is trying to emerge from bankruptcy) sued the Air Force for taking steps to procure electricity competitively in New Mexico. Ultimately the Air Force settled the case by signing up with El Paso Electric for a fixed-term contract at a reduced rate. El Paso Electric then presented the agreement as evidence of its ability to lock in an important, large customer. Federal agencies should all be aware of this leverage. I would suggest that agencies not push the envelope of competition now. I don't think they have the institutional will to fight those battles in court. We do not have the resources to challenge the sole source issue at the moment. I would again offer the example of what the Air Force tried to do in New Mexico. While I think legally federal agencies have the authority to buy competitively, I question our will to defend this principle. (Notwithstanding the negative experience of the Air Force, El Paso electric did ultimately reduce its rates.) Also if the federal agencies are too aggressive in asserting their rights to competitive acquisition, they will become the lightning rod for lawsuits and possibly be a catalyst for a political solution to the issue. CONCLUSION Federal agencies need to start planning now, because acquisition planning takes time. We need to determine what we plan to do when

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competition arrives, because it will arrive, and probably before we are prepared for it. In the meantime, agencies should use their increasing leverage with utilities to gain concessions on prices and services. But they should not attempt to push the envelope of competition now. The recent FERC decision attempts to clarify a number of important issues which may have cost implications for federal agencies. These issues will need to be examined thoroughly in the light of evolving legal and regulatory action.

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ADDITIONAL CONSIDERATIONS IN THE ELECTRIC COMPETITION DEBATE

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ADDITIONAL CONSIDERATIONS IN THE ELECTRIC COMPETITION DEBATE Timothy Brennan University of Maryland

My primary industry experience is in telecommunications rather than electricity, yet there are some lessons from the former that apply to electric competition issues. Two involve the speed at which competition comes into an industry and the controversial nature of competition in traditionally regulated industries. Regarding those controversies, I want to address three topics: discrimination (or "comparable treatment") issues, mergers, and stranded costs. COMPETITION DOES NOT COME QUICKLY The history of the regulatory reform in the telecommunications industry provides some useful insights into the speed, or lack thereof, at which competition comes to regulated industries. In 1959, the Federal Communications Commission inadvertently opened the door to long-distance competition when it gave firms the authority to set up private microwave systems to serve their internal needs. After firms realized that these networks could be used to provide commercial long-distance service, the Justice Department filed its antitrust case against AT&T, claiming that AT&T had anticompetitively abused its local exchange monopolies to prevent long-distance competition from developing. This case took until 1982 to settle; it was never litigated to a conclusion. In accord with that settlement, AT&T spun off its local telephone operations, creating the Regional Bell Operating Companies (RBOCs). The court also imposed restrictions on the RBOCs to prevent them from

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reinstating the former AT&T's vertically integrated structure. These "line of business" restrictions kept the RBOCs out of long-distance service, equipment manufacturing, and information services. By late 1986, the Justice Department changed its mind about the merits of much of what it had been attempting to achieve in antitrust litigation against AT&T, not just in this case, but in earlier cases going back to at least 1949. This change showed up most noticeably in a 1987 court review of the line of business restrictions, which the Department advocated repealing for the most part. The court reviews of those restrictions took until mid-1991 to resolve; the resolution resulted in the elimination of the information service restrictions but retention of the equipment manufacturing and long-distance bans. This decision, in turn, set off a new round of attempts and negotiated arrangements to enter these markets. Various tries in the courts and Congress eventually resulted in passage of the Telecommunications Act of 1996. The Act establishes conditions under which the RBOCs can enter these markets, but with various structural and regulatory provisions that remain in place until 2001. Moreover, most of the extensive state public utility regulation of telephone service, like that of electricity, remains in place. The point of reviewing this history is that competition in telecommunications, in fits and starts, took at least 42 years to achieve (1959 to 2001), and may not be finished yet. Similarly, implementing competition in electricity may not happen instantly and smoothly. Electricity is, in many ways, more complicated than telecommunications. Information is much easier to move around than power. Telecommunications deregulators did not have to deal with loop flow, load balancing, and the system's blowing up or browning out— although they did have to ensure that phone calls would still go through. And, notably, there wasn't a $200 billion stranded cost issue to resolve. We therefore cannot expect that competition in electricity will be achieved overnight. It is by no means simply a technical problem to which people in some government office can work out details with the automatic assent of the utilities, independent power producers, industrial users, consumers, environmentalists, and regulators. The proceedings will be contentious. Three of the most prominent matters of contention are issues of discrimination, mergers, and the recovery of stranded costs.

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DISCRIMINATION Discrimination is an issue because the utilities that own transmission and distribution grids might unduly give preferential service in a variety of dimensions to the generators they own, and lower quality service to independent power producers. The primary reason to worry about discrimination is that the transmission and distribution grids will still be regulated. A utility would have a financial incentive to evade the regulation by, say, using its transmission monopoly to favor its own generation company and impose lower quality service on others. Such a move would allow the firm to reduce competition from these independent power producers, raise the price it charges for its own generated electricity, and thus capture indirectly the profits it can generate because it is the only transmission provider in town. From my experience in antitrust matters, I believe that there is nothing wrong in general with firms, integrating into other businesses and favoring their own affiliates. However, regulation creates particularly anticompetitive incentives to do so. Those harmful incentives were a major reason for the breakup of AT&T and the consequent line of business restrictions placed on the RBOCs. Regulation presents a similar cause for concern here. Will we have to adopt such extreme remedies as divestitures in the electricity industry? It is hard to be optimistic about preventing discrimination solely through regulations and laws. For example, some may believe that we need not worry about discrimination because the Energy Policy Act and Federal Energy Regulatory Commission (FERC) will take care of the problem. Relying on statutory language alone, however, is too optimistic. Mitigating discrimination requires diligent regulators who have the resources, ability, and will to ensure that firms realize they cannot successfully discriminate. Clear and ready implementation cannot be guaranteed, and years of subsequent litigation are predictable. I would like to be wrong about this, but the experience in telecommunications does not give me much comfort. STRUCTURAL APPROACHES TO DISCRIMINATION One irony is that we are considering regulatory or structural boundaries separating transmission from generation to prevent discrimination while at the same time, via the Telecommunications Act, we

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are allowing telephone companies to reintegrate. But there is a facet of that Act directly affecting utilities—electric utilities' entry into telecommunications and video markets. I wonder whether the recent FERC order imposes rules separating the operations of generation and transmission that are as stringent as those the Telecommunications Act imposes between local power distributors and their telephone or cable television operations. A second issue is that, if purely functional unbundling of transmission and generation would really be effective, why should the nation not go all the way and order a divestiture? The point of vertical integration is to encourage coordination in production and operation, to reap what economists call economies of scope. But coordination with one's affiliate necessarily implies discriminating in favor of that affiliate and not offering competitors comparable treatment. If companies are allowed to remain nominally integrated, what can they gain if we impose rules that are going to prohibit this coordination? This debate was at the heart of the AT&T divestiture and continues to dominate telecommunications policy today. PREVENTING DISCRIMINATION DOES NOT ELIMINATE MARKET POWER A final point about discrimination is that many regard it as a substitute for price regulation. It is not. If a utility is charging the same monopoly price to everyone, it is not discriminating, yet it is fully exercising its market power. Yet if this is so, why are anti-discrimination rules so popular? To understand this issue, one must assume the perspective of the industrial users who compete with each other in other product or service markets. To oversimplify a bit, these buyers do not care much about the absolute price they pay for electricity so long as their competitors are not paying less. It is the competitive advantage created by relative prices that matters to them. If my competitors get a better deal than I do, I lose in the market, but if the price is higher for everyone, markets will pass that cost on to consumers. If industrial buyers are better organized in lobbying FERC and state regulators, they may lobby very hard for nondiscrimination rules regarding power delivery, but not lobby nearly as hard for lower rates for transmission and distribution. The end-users, who really do care about absolute prices, such as residential users or the federal government, may

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not be able to benefit by letting this regulatory process run its course. One cannot assume that, when industrial buyers protest at government hearings about something a regulated utility is doing, they are necessarily speaking for consumers or the economy as a whole. MERGERS The Justice Department and Federal Trade Commission traditionally do not care whether a proposed merger is a good idea from the standpoint of the merging companies. I can see why FERC or a state regulator might want to oversee investment decisions by regulated companies, but the antitrust authorities are not equipped to second-guess capital market decisions. What those authorities do care about is competition. How to judge the effect of utility mergers on competition presents some peculiarly difficult policy issues. In both the electricity and telephone industries, mergers are being proposed before the regulations are settled. The determination of the economic effects of those mergers depends on whether the merging utilities will compete more than they do now in their separate franchise areas, and whether other power generators will also be able to compete effectively against them in those service areas. These crucial issues depend very much on the rules for transmission pricing that have yet to be promulgated, litigated, and settled. A speculative concern is that utilities are merging because they have predicted that they will be each other's primary future competitors. One way or the other, because policy decisions will make the future substantially different from the present, it is not clear how antitrust authorities and courts will effectively protect prospective competition. I hope they can do so. STRANDED COSTS Last and not least is the hotly contested matter of the $150 to $200 billion in stranded costs. This issue need not be regarded as solely a matter of fair allocation of a payment burden between stockholders and consumers. There is an efficiency issue here, particularly when we take long-run regulatory policy into account. On the one hand, we want rules that force the government to honor its commitments. Otherwise, investors are not going to supply the capital

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necessary to provide services to the public, through either government procurement or regulated industries. That statement is as true for electric power companies as it is for firms that build aircraft carriers. On the other hand, if the rules are too generous, overspending may occur—also equally true of utilities and defense contractors. Consequently, cost recovery policies are not simply a matter of fairness. They determine whether investors put too little or too much into the facilities used to supply regulated (or publicly procured) goods and services. When the terms of the contract between the investors and the public are explicit, there should not be a real debate. With regard to stranded costs, for example, if FERC (or a state regulator) and a utility both agree that there was a contract that included a commitment to compensate utilities if the government adopted procompetitive open-entry policies, it would be difficult for someone to claim that there was no such thing. But when the contingency is only implicit— and the fact that advocates of cost recovery invoke a "regulatory compact" rather than point to a contract suggest that the contingencies here are implicit—we have a problem in contract interpretation. What Does One Do? The economics of contracting suggests two factors for courts and policy makers to consider in addressing how the utilities and government would have specified how the costs of competition to utilities would be borne. The first is to ask who was in the best position to predict whether competition would occur, and thus be in the best position to adapt to it or insure against it. The second is to ask who had the most influence over whether competition would occur. There are certainly some fairly strong arguments for assigning an obligation to the government to provide for stranded cost recovery. The government certainly had some influence over policy developments in this area, and also may have forced utilities to incur costs that they might not have otherwise incurred had they been free to take the risk of future competition into account. Contracts for high-cost renewable power sources mandated by the 1978 Public Utility Regulatory Policies Act (PURPA) may well fall in this category. However, there is another side as well. For example, utilities may have been in a better position than regulators to predict the technological changes that would lead to competition. To provide some answers to this question, it might be interesting to look at speeches utility executives made in the early 1980s, following

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PURPA, when the prospects of future competition became significant. They might have said that utilities would like to respond to competitive prospects, but that regulators were controlling most of their investment decisions. Alternatively, they might have implied that utilities are forward looking enterprises, initiating and implementing grand ideas at the cutting edge of technological development. Would the utilities have seemed back then to be the puppets of the regulators, as advocates of stranded cost recovery now intimate? Or were they continuing to make investments on their own in the face of the possibility of future competition from independent power producers? If the former, the government is the breaching party here and should be liable, but the government presumably ought not be held to an implied promise to cover all expenses the utilities initiated. Do These Efficiency Considerations Really Matter? In the end, these remarks may be only the musings of an idealistic economist. The case for stranded cost recovery may have more to do with political realities. Today, some of the utilities essentially reminded us that if stranded costs are not covered in some way, they will tie up competitive initiatives in the courts until the 22nd century. Other commentators have suggested that a failure to ensure stranded cost recovery is akin to an unconstitutional "taking" of property. While that issue, too, is usually couched as a matter of fairness, some research I have done with colleagues at Resources for the Future suggests that we might want to compensate parties with political clout specifically to persuade them not to oppose policy changes that would lead to a more efficient marketplace. We may not like having to pay that price, but in reality, we may be in a worse place if we do not. CONCLUSION This conference has shed a great deal of light on the issues facing the electricity industry, its regulators, and federal facilities managers as we proceed down the path to competition. A similar history in telecommunications warns that the trek will be slow and bumpy. Discrimination concerns, mergers, and cost recovery are three major problems to be settled, but others are certainly crucial: retail marketing,

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load management, transmission pricing, and environmental protection, to name a few. I hope that these and other discussions will lead to the collective knowledge and wisdom to let us avoid the mistakes of the past and move expeditiously to a competitive and vibrant electricity industry.

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SPEAKER BIOGRAPHIES

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SPEAKER BIOGRAPHIES

Timothy Brennan is a professor of policy sciences and economics at the University of Maryland's Baltimore County campus and a Senior Fellow of Resources for the Future. His research has examined regulatory economics, antitrust policy, and information issues, including regulation of broadcast content, the First Amendment, and copyright. He has also published articles on the ethics and philosophy of economics. He is co-author of Shock to the System, a book on the restructuring of the electricity industry published by Resources for the Future. Previously, he was an associate professor in the telecommunications and public policy programs of George Washington University, and before that an economist in the Antitrust Division of the U.S. Department of Justice. He holds a master's degree in mathematics and a Ph.D. in economics, both from the University of Wisconsin. Millard E. Carr is Director for Energy and Engineering in the Office of the Assistant Secretary of Defense for Economic Security. He is responsible for developing and implementing the Defense Department's policy for energy resource management, design and construction criteria for facilities, and utility procurement. He acts as Chairman of the Defense Utilities Energy Coordinating Council and as Department of Defense representative on the Federal Interagency Energy Policy Task Force and the Federal Interagency Electric Industry Restructuring Group. He is the program manager for the Department's Energy Conservation Investment Program and Federal Energy Management Program. Mr. Carr holds a bachelor's

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degree in mechanical engineering from George Washington University and a master's degree in public administration from the American University. Jim Clarkson is Director of Southeastern Power Marketing for Heath Petra Resources, Inc. Previously, he was an energy manager with a large manufacturing company and has worked with a large utility. He is a director of the Institute for Energy Research. Mr. Clarkson holds degrees in engineering and business. Wilbur C. Earley is Director of the Division of Electric Policy in the Office of Economic Policy at the Federal Energy Regulatory Commission. Earlier, he was Chief of the Office's Economic and Strategic Analysis Branch for electric policy. Before joining the Office he served in the Commission's Office of Electric Power Regulation. He received a bechelor's degree in economics from the University of Maryland. Mark Ginsberg is Director of the Federal Energy Management Program (FEMP) at the U.S. Department of Energy. He has responsibility for helping Federal agencies implement Presidential and Congressional energy savings goals. FEMP provides leadership in the federal sector to achieve energy and dollar savings while introducing new technologies into the marketplace. Mr. Ginsberg leads several interagency committees and a consortium of Federal laboratories to deploy cost-effective technologies in energy consuming government operations. In April 1993 Mr. Ginsberg was asked to chair an interagency team on the Greening of the White House. John Hanger has served as a Commissioner of the Pennsylvania Public Utility Commission since 1993. His main concerns are the restructuring of the gas, electric, telephone, and water industries, as well as matters affecting Pennsylvanians with low or fixed incomes, such as the Low Income Home Energy Assistance Program. From 1988 to 1993 he was Legal Counsel to Commissioner Joseph Rhodes, Jr. He worked for Community Legal Services, Inc., from 1984 to 1988, including service as Public Advocate for Philadelphia's municipal gas and water customers. As Nebraska State Coordinator for PRAXIS, Inc., from 1979 to 1981, he organized efforts to improve nutrition assistance programs for senior citizens and low income families. He received a bachelor's degree from Duke University, and a law degree from the University of Pennsylvania.

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Ross C. Hemphill is Director of Resource Strategies at Niagara Mohawk Power Corporation. He works full time on strategic planning and policy studies, notably issues related to the company's transition to a competitive market. Before assuming that position, he was Director of Electric Pricing at Niagara Mohawk. Earlier, he worked as a private consultant and held various positions with the Energy Exchange of Chicago, Argonne National Laboratory, American Electric Power, the National Regulatory Research Institute, the Illinois Commerce Commission, and the General Telephone Company of Indiana. He holds a bachelor's degree in economics from Lewis University; a master's degree in economics from Indiana State University; and a Ph.D. in resource economics from Ohio State University. John L. Jurewitz is Manager of Regulatory Policy at the Southern California Edison Company. Before joining the company in 1978, he was an assistant professor of economics at Williams College and Pomona College. He continues to teach courses in energy policy and in environmental and natural resource economics at Pomona College and the Claremont Graduate School. He holds a bachelor's degree from the University of San Francisco and a Ph.D. in economics from the University of Wisconsin. Douglas M. Long is Program Manager of the Environmental and Energy Advisory Branch, Advisory and Compliance Division Office, at the California Public Utilities Commission. He is responsible for providing technical support for administrative law judges in proceedings before the Commission. He also manages agency compliance with the California Environmental Quality Act. He received a Bachelor of Economics degree from James Cook University of North Queensland and bachelor's and master's degrees in accounting from Golden Gate University. He is a Certified Public Accountant.

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GLOSSARY

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GLOSSARY

Aggregation—

The assembly of power from various sources for sale to retail customers. Competition Under California's proposal for retail competition, a Transition Charge— surcharge to be added to customers' electricity bills to allow for the recovery of ''stranded costs" (q. v.). Energy Policy Act— Act of Congress, passed in 1992, that, among other provisions, gives the Federal Energy Regulatory Commission authority to require transmission owners to open access to their systems to third party suppliers of energy. Exempt wholesale Under the Energy Policy Act of 1992 (q. v.), nonutility generators— owners of generation capacity that are qualified to sell in the wholesale power market. Federal Energy The federal agency charged with regulating interstate Regulatory commerce in electric power (both wholesale sales and Commission— mergers and acquisitions). Independent Power A generator not owned by a regulated utility. (See Public Producer— Utility Regulatory Policies Act of 1978.)

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GLOSSARY

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Independent System Under the California plan for retail competition, an entity Operator— established to operate the transmission and distribution

system, enforcing nondiscriminatory access to generators and buyers of power. Load following— The adjustment of power levels on a transmission grid to accommodate changing demands for power. Pancaking— The imposition of multiple charges for transmission of power through the service territories of several utilities, with each utility applying its own charge. Public purpose Utility programs intended to serve the public interest, but not programs— in the immediate interest of the utilities. Examples include research and development, rate assistance to low income customers, and energy efficiency improvements for customers. Public Utility Act of Congress passed in 1978 that, among other provisions, Regulatory Policies requires electric utilities to buy power from independent Act (PURPA)— generators, at prices representing the utilities' "avoided costs" of adding the corresponding amounts of generation. Qualified facility— Generating facilities that are independently owned and sell power to utilities under contracts based on fuel price forecasts in the past. Reserve generating Generating capacity held off line to meet peaks in demand capacity— and/or to supply power during scheduled or unscheduled outages of generation. Real-time pricing— The pricing of power to reflect the variation of the cost of generation over time. Stranded costs— The embedded costs of generating capacity that would be rendered uneconomic by market competition in generation. Unbundle— To divide into separate commodities the products and services now provided by vertically integrated utilities. Under FERC Orders 888 and

Competition in the Electric Industry : Emerging Issues, Opportunities, and Risks for Facility Operators, National Academies Press,

Copyright © 1996. National Academies Press. All rights reserved.

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Wheeling—

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889, public utilities must file tariffs providing nondiscriminatory transmission access to all wholesale users. Several states are considering unbundling retail services as well. The transmission of power from one utility's territory to another's, often for sale to a customer by a third party.

Competition in the Electric Industry : Emerging Issues, Opportunities, and Risks for Facility Operators, National Academies Press,