INDUSTRY AND ENERGY DEPARTMENT WORKING PAPER ENERGY SERIES PAPER No. 12 Recent Developments in the U.S. Power Sector and Their Relevance for the Developing Countries February 1989 * ; AX D~~~~~~~~~~~~~~~~~~~~~~~~~ RECENT DEVELOPMENTS IN THE U.S. POWER SECTOR AND THEIR RELEVANCE FOR THE DEVELOPING COUNTRIES by Mohan Munasinghe Arun Sanghvi February 1989 Copight (c) 1989 The World Emank 1818 H Street, NW Washington, DC 20433 USA This paper is one of a series Issued by the Industry and Energy Department for the Information and guidance of Bank staff. The paper may not be published or quoted as representing the views of the Bank Group, nor does the Bank Group accept responsibility for its accuracy or completeness. Mohan Munasinghe is Chief of the Energy and Infrastructure Operatiois Division, LAC-CD1. Arun Sanghvi Is a consultant. Abstrct This volume examines the evolution of the U.S. power sector over the past 100 years and explains its present mix of private and public electric utilities functioning under both federal and state regulation. The particularly rapid developments during the last decade or so are reviewed In detail Including PURPA legislation, cogeneratlon activities, sale of dedicated generation, deregulation and privat!zatlon. The U.S. experience provides an opportunity for the developing countries to benefit from the good features of U.S. power sector development while avoiding the pitfalls. The authors suggest that power sector performance In the developing countries could be increased by: 1) strengthening competitive forces of the market place; 2) limiting regulation to those aspects of the sector which cannot be self-regulated by competitive forces 3) to the extent regulation Is necessary, applying It to both private and public power, 4) increasing efficiency through cogeneratien and decentralized (independent) power generation, and 5) encouraging private t-ector participation In a variety of ways ranging from equity participation to provislon of management services. The study concludes that establishing a sector structure that encourages efficiency through competitive, market type disclpline Is a more fundamental issue than the type of ownership, L.e., public or private. TABLE OF CONTENTS 1. Summary and Conclusions ........................................1............. . 2. Introduction ..5 2.1 Background, Study and Objectives and Scope. 5 2.2 Structure of Report .6 3. Characterization and Assessment of the U.S. Power Sector.. 7 3.1 Organization and Industry Structure .7 3.2 Performance Evaluation and Main Issues ................................... 12 3.3 Effects of Regulation and Ownership Patterns .18 4. PURPA and the Development of Cogeneration and Independently Owned Power Production .27 4.1 Background .27 4.2 Pertinent Legislation .................... . . ........................ 30 4.3 Impacts: Present and Future Potential .35 4.4 Some Policy Issues .37 S. The Emerging Competitive Philosophy: Consumer Choice, Deregulation, and Privatization .44 5.1 Recent Developments .44 5.2 Privatizatlon and Deregulation Options .47 6. Implications of U.S. Experience for Power Sector Efficiency and Restructuring In Developing Countries .51 Notes: ................. ........................................ 57 Annex 1: Organizational History of the U.s. Power Industry .64 Annex 2: Power Sector Structure In Selected Foreign Countries 72 A-65-9ix : Supporting Information on PURPA .81 Selected Bibliography .... 86 1. SUMMARY AND CONCLUSIONS The evolution of power systems in developing countries, like developed countries, has been extremely varied. Within developing countries, however, there has been an increasing trend (especially within the last few decades), towards govemment ownership and centralization of power sector institutions. In contrast, in the U.S. and a few market economies, the major portion of the power sector is organized along the lines of private ownership with public oversight In between these two structural forms of "public power" and "private power" may be found several other organizational and market-environments within which the power sector functions in these and other countries. The rationale for the di'ferent modes of organization are usually based on a diverse set of considerations including ideological, sociopolitical, economic, legal, and financial considerations. Significant differences also exist on the performance-side, where the degree of "success" achieved by the power sector in meeting national goals and objectives also varies substantially. Indeed, evidence suggests such variation to be sufficiently large as to merit a closer examination and evaluatior of the major linkages between sector organization and performance. Such an analysik, could provide valuable insights for enhancing sector efficiency by appropriate reorganization and restructuring. The question of how bast to organize the power sector continues to fuel an ongoing debate which began when electricity was first generated over a century ago. In this regard, the U.S. power sector today and the evolutionary process which brought it to the present state, offers a particularly fertile ground for developing such insights. With this as background, the objective of this report is to review the U.S. experience and emerging trends, and present its general implications for power sector efficiency and restructuring initiatives in developing countries. However, country specific prescriptions are not developed, since they will generally vary from country-to-country and must be conditioned to the prevailing realities. Contrary to a commonly held opinion, the electric utility industry in the U.S. is not homogenously organized solely along the lines of private ownership and public regulation. Whereas investor owned utilities (IOUs) are a dominant factor in the market, about a fourth of the market is organized along the lines of public ownership. - 2 - Since its inception, the industry has been the subject of almost continuous regulatory soul searching which periodically led to comprehensive investigations, debates, reports, hearings and calls for reform and restructuring. As a consequence of these political, ideological, and social forces, and because of changing technological and economic conditions, the industry structure -- ownership, organization, control and regulation -- has evolved through a process of dynamic accommodation, and adjustments. In this process several different structures evolved, and indeed most such forms exist today. Despite the fact that over a century of experience has accumulated, answers to the basic questions at hand still do not command a general consensus. Nevertheless, if 100 years of U.S. experience suggests anything it is that: - The structure of the power sector should be such as to induce the type of performance oriented discipline that is typified by a competitive market structure. - Regulation as a means for enhancing performance has many limitations. This suggests that regulation by regulatory bodies be confined as far as possible only to those aspects of the sector which cannot be adequately self-regulated by competitive forces. - To the extent regulation is necessary, it should be applied to provide the necessary control and discipline of both private and public power institutions. Experience indicates that when resources are allocated by individuals who answer neither to the marketplace nor Lo the general public, the potential for mismanagement and gross misallocation of resources is great, whether such decisionmake.s are in the private or public, sectors. At the same time, opportunities and incentives to strengthen management and staff must be enhanced. - To the extent some regulation is required, it should be concerned more with achieving overall results. It should not seek to control every aspect of a utility's planning and operations. Rather it should provide flexible but clear and unambiguous signals that impose a minimum of interference on the managers in-charge. A key point emerges from the foregoing. The extent to which the market organization and any regulatory control instills the rigors of a competitive market type discipline on its participants is a more fundamental issue than type of ownership (i.e., public or private). Thus, even if some elements of the market are -3 - under public ownership, it is extremely important that they also be subject to such discipline, because ultimately, performance boils down to managerial attitudes and incentives. The U.S. experience suggests that the injection of competitive elements -- actual or threatened -- are likely to do more to help achieve higher standards of performance than regulation, or other control and oversight interventions. Some specific options discussed in this report that potentially offer signfficant efficiency gains by virtue of the fact that they introduce and strengthen competition, are: - Bidding by private sector for new generation capacity - Franchise competition - Privatization - Foreign enclave operation Several developing country governments are already exploring thsse and related possibilities, because of the difficulties in their power sectors (e.g., Jamaica, Pakistan, Sri Lanka, Turkey, etc.) In addition, two other options are potentially very important in the context of many developing countries: - incentives for decentralized (independent) power generation such as cogeneration, dedicated generation for sale, etc. release of existing captive generation. Before such potential can be realized, the governments and power authorities concerned will have to develop a clear policy regarding interconnection requirements, tarffs, reliability, wheeling, financing, accounting, institutional issues, and regulatory aspects. The U.S. experience with the Public Utilities Regulatory Policies Act (PURPA) of 1978 provides a good starting point for tailoring such initiatives to specific countries. Of all the legislative responses in the U.S. to the "energy crisis" of the 1970's, PURPA can perhaps be characterized as a very important energy policy initiative, that is likely to have far reaching implications into the future. The competitive forces unleashed by PURPA (if significantly unchecked in the future), -4 - signal a significant restructuring of the power sector market during the remainder of this century. This trend has already established a strong foothold and gained considerable momentum. Finally, developing countries may be able to profit from the U.>. experience by examining (and avoiding) some of the pitfalls that have emerged frm the application of PURPA in its existing form. Typical problems include: 1. Pressure on utilities to purchase from private generators at prices that exceed their full avoided costs, including cases where the utility is obliged to pay capacity costs to the private supplier, while having excess capacity. 2. Utilities being obliged to offer incentive payments to encourage private generators (in oxcess uf avoided costs), or having to deviate from optimal load dispatch or system operation because of such purchases. 3. Restrictions on the utilities ability to solicit bids for private capacity, on a compeitive basis. - 5- 2. INTRODUCTION 2.1 BACKGROUND, STUDY OBJECTIVES AND SCOPE The evolution of power systems in developing countries, like developed countries, has been extremely varied. Within developing countries, however, the power structure is generally government owned and operated either as a parastatal agency or within a ministry. In contrast, in the U.S. and a few market economies, the major portion of the power sector is organized along the lines of private ownership with public oversight. In between these two structural forms of "public power" and "private power" may be found several other organizational and market-environments within which the power sector functior.s in these and other countries. The rationale for the different modes of organization are usually based on a diverse set of considerations ranging from economic, social, legal, and financial to political and ideological. Considerable differences in performance, also exist, where the degree of "success" achieved by the power sector in meeting national goals and objectives, also varies substantially. Indeed, evidence suggests such variation to be sufficiently large as to me;it a closer examination and evaluation of the major linkages between sector organization and sector effectiveness. Such an analysis could provide valuable insights for enhancing sector efficiency by appropriate reorganization and restructuring. The UI.S. power sector today, and the evolutionary process which brought it to the present state, offers fertile ground for developing such insights. In particular, since its inception on 4 September 1982, when Thomas Edison's 560 kW Pearl Street generating station in New York began supplying 85 customers with 400 lamps, the industry has been the subject of almost continuous regulatory soul searching which periodically led to comprehensive investigations, debates, reports and hearings and calls for reform and restructuring. As a consequence of these political, ideological, and social motivated forces arid because of changing technological and economic conditions, the industry structure - ownership, organization, control, regulation -- has evolved through a process of dynamic accommodation, and adjustments. In this process, several different structures evolved and indeed most such forms exist even today. -6- A review of this regulatory history of the industry and the forces that shaped it, provide useful insights about certain basic questions that define the objectives of this effort: - Has the combination of private ownership and public control (regulation) that characterizes the investor owned segment of the U.S. utility industry been wise and successful? * What are the major issues and emerging trends in the industry today? - What are the main shortcomings of the different modes of organization presently found? What organizational forms are economically superior? In particular, can even greater reliance on either the forces of competition, public ownership, or private ownership provide a more effective alternative? - How effective is regulation as a substitute for competition? As a substitute for public ownership? - Are pui.licly owned power systems a better means of organizing the pocver sector? - What impacts have legislative initiatives such as PURPA, had on the market environment faced by the utilities in the U.S.? - What is the relevance of PURPA-type legislation for the developing countries? 2.2 STRUCTURE OF REPORT This report is organized as follows. Section 3 describes the ownership and organizational structure of the U.S. power sector and presents an assessment of key aspects of the market. Section 4 discusses the implications of the PURPA legislation which has stimulated increased competition in the marketplace and may help to set a trend towards further regulatory reforms. Section 5 highlights the emerging competitive forces at work in the power sector and discusses their potential impacts in terms of restructuring the sector. Finally, Section 6 develops some implications of the U.S. experience for efficiency and restructuring initiatives in developing countries, followed by several Annexes. -7- 3. CHARACTERIZATION AND ASSESSMENT OF THE U.S. POWER SECTOR 3.1 ORGANIZATION AND INDUSTRY STRUCTURE Contrary to a commonly held opinion, the electric utility industry in the U.S. is not homogenously organized solely along the lines of private ownership and public regulation. Exhibits 3-1 and 3-2 help to characterize the pluralistic nature of the industry market structure based on 1984 data. Private ownership is represented by about 250 Investor Owned Utility (IOU) companies that together account for about 77 percent generation capacity of 673,000 MW and generation of 2,416 Terawatt-hours (TWh). These companies together serve about 73 million customers out of a national total of 96 million. Whereas lOUs are a dominant factor in the market, about a fourth of the market is publicly owned. Within the "Public Power" systems, four broad classes of organizations can be identified. The six federal systems comprise the five Power Marketing Agencies (PMAs) 1/ and the Tennessee Valley Authority (TVA). Until recently, the five PMAs have essentially marketed hydro power from federal dams, many of which are owned and operated by the Army Corps of Engineers or the Bureau of Reclamation. Municipal systems (MUNYs), Public Utility Districts (PUDs) and State Power Projects together comprise about 2,200 systems, and account for 9 percent of generation. Finally, there are about 1,000 rural electric cooperatives (COOPs). As regards the extent of functional integration, most lOUs are completely vertically integrated. On the other hand, the vast majority of COOPs, MUNYs and PUDs own distribution facilities only. Forty-six COOPs own some generation and transmission facilities (G&T COOPs). Under the "public preference" provision in federal and state laws, MUNYs, COOPs, and PUDs have first call on available low cost power from federal or state hydro projects. 2/ However, public systems (MUNYs, COOPs, and PUDs) also participate as buyers in the wholesale bulk power market to meet their remaining need for power. This "requirements market" -- sales for resale -- functions through the establishment of long-term power purchase contracts between respective IOU supplier(s) and the purchasers. The supplying lOUs treat this load as a firm Icad and are obligated to serve this load in very much the same manner as they plan and build capacity for their native retail loads. -8- EXHIBIT 3-1 INDUSTRY MARKET STRUCTURE TODAY (Excluding Industrial Plants) ItaaUmd Custmare Capqty Gaeretlon rcuit Kiles ttber f 6 9 uett df of 229. kV Lnes *018lip lTe SySte 10 2 % 10 IWI FUnction tatXno C.z (MiLes) PRIVATE 474,000 o ICU 250 73 515,000 77 1,84* 77 ct are vertically lrqtar- PUINII 126,000 o RPA Cooerativ 1,000 10 25Q000 4 102 4 only 46 are Gl$T W . Rest (amE) ae dst1buU= bl. • Federal Systaw 2/ 6 - 63,000 9 254 10 Bkll1 pum prati and tram_0xt= o %ndc la (MM) 37?000 5 24 3 Mtldy distributioz. 2,200 13 o Ptin matrIcter 33,000 5 137 6 tarpr tM am gm prer- (it) state t ftojts mv mcd bl tranmssi 4J MlYL 3,456 96 673,000 100 2,416 100 600,.)O 1/ Sa9 E: Satistcal yearto* 1984 azl Ibe Publc aftts df PblC Patw," Ahrin, Publi Pasr AsmDciar Lon (APPA) W 1984. 2/ These cwist df (1) five Pasr tketitq Agereie (Mks): Alasa (APA). EtowvWa (BPA), Scuthtetern (SEPA). S _utumn (SIPA), and Wderan Ara (WA); & m of Real£ mtan; &w Corps of E111w8; ard TVA. 3/ e.g., tLAUP, SlD, Austin mletaric Utlity. 4/ e.g., Nb YoxL Power Auttordty (NPA), Salt River Project, tamr Golored. River hoktrity (bus), mauud Etiver 3= Authotity (oklalF), South Caolina hblic Seaice Authority. Inter-Utility Coordination and Pooling There exists a substantial amount of inter-utility coordination. This is achieved via a variety of mechanisms, some of which are formal binding agreements, whereas others are informal arrangements. A broad taxonomy for characterizing the extent of existing coordination and power pooling arrangements is depicted in Exhibit 3-3. Two distinct forms emerge: "tight" power pools and "loose" power pools. Whereas specifics may vary considerably, generally speaking, tight pools represent highly integrated and formalized agreements. They typically provide for centralized dispatch of all generating facilities, reserve sharing, coordination of unit maintenance, and adherence to an agreed shortage emergency. Need for capacity (from a reliability perspective) is generally established by pool level reliability standards applied to pool loads. Each participant is then allocated a share of capacity that it must provide to the pool. Legal agreements may also stipulate financial penalties if such obligations are not met. Most tight pools, however, do not necessarily adhere to least cost planning principles on a pool basis. In other words, each participant determines what mix of generation to add to meet its own load. Its obligation to the pool is primarily with respect to the amount of capacity to be made available. In this regard, holding company power pools are more likely to follow least cost planning principles at the pool level, e.g., Middle South Utilities, Southern Company System. 3/ Loose pools have achieved a significantly lesser level of integration and coordination than tight pools. Again, the specifics vary in each case. However, broadly speaking, the coordination represents consultations and information sharing about the members' respective loads and resources, reserve sharing in times of need, how best to jointly meet their responsibility for maintaining the adequacy of the bulk power supply within the North American Electric Reliability Council (NERC) region to which they belong, etc. Such coordination is generally on a voluntary basis without any provisions for enforcement. Tight pools represent about 25 percent of installed capacity nationwide, and loose pools repi esent an additional 20 percent of total generating capacity. * 10- EXHIBIT 3-2 INDUSTRY STRUCTURE: Source of Energy by Ownership and Disposition (109 kWH) Federal Other IOUs COOPs System MUNYs Publics Total A. SOURCES l/ 1. Own Ceneration o Fossil/Steam 1,488 101 67 54 56 1,766 o Nuclear 277 .3 25 4 22 328 o Bydro 84 .3 162 16 59 321 o Internal Combustion .6 .2 - 1.1 1 2 1,849 TT T5-4 74 13 2,416 2. Industrial Self - - - - - NIA2/ Ceneration for Self Use 3. Industrial Sales to - - - - - 20 Utilities 4. Imports from Canada and - - - - - 42 Mexico 2,478 3. DISPOSITION 3/ 1. Sales to Ultimate - - - - - - Customers 2. Esports - - - - - 2 3. Energy Used by Producer - - - - - 3 4. Company Use and Free - - - - - 12 Service 5. Lost and Accounted For - - - - - 176 2,478 I/ Source: EEI Statistical Yearbook, 1984. 2/ Under 2% of own generation. 3/ Approximately 802 of IOU sales are to ultimate customers, 16 represent sales-for-resale and 4% represent losses and other accounts. Comparable approximate percentages for other categories are: COOPs (811, 81, llZ); Federal Systems (22%, 74%, 46); and MUNYs and Other Publics (6X, 33%, 6%). - 1 1 - EXHIBIT 3-3 EXTENT OF HORIZONTAL COORDINATION MARKETS "TIGHT POOLS" Generating Capability Summer 1979 Affected States Name of Pool. Megawatts ME, VT, NH, MA, New England Power Pool (NEPOOL) 21,294 RI, CT NY Now York Power Pool (NYPP) 29,742 PA, NJ, MD, DE Pennsylvania-New Jersey-Maryland 44,891 Interconnection (P3K) PA, WV, MD, Ohio, Allegheny Power System, Inc. (APS) 6,822 (Holding Company) IN, Mi, OH, UV, American Electric Power System 20,123 KY, VA, TM (AEP) (Holding Company) LA, KS, AR, NO Middle South Utilities, Inc. (MSU) 12,177 (Holding Company) KS, AL, GA, FL Southern Company System (SOCO) 23,909 (Holding Company) Subtotal 158,958 "LOOSE POWER POOLS" OH, PA Central Area Power 15,147 Coordinat-on Group CAPCO IL, NO Illinois-Missouri Pool IL-MO 13,480 HI Michigan Electric Coordinated System 15,791 VI, IA, HU, ND, Kid-Continent Area Power Pool (KAPP) 24,527 SD, NE, MT KA, MO Missouri-Kansas Pool (MOKAN) 8,879 OR, VA, ID, MT Pacific Northwest Coordination 32,292 Agreement (PNCA) CA California Power Pool (CPP) 28,870 TX Texas Utilities Company 17,336 (Holding Company) Subtotal 156,322 Source: (321 - 12 - 3.2 PERFORMANCE EVALUATION AND MAIN ISSUES Any attempt to appraise the performance of the power sector must begin by first defining the underlying objectives. Broadly speaking, these can be characterized as the provision of adequate and reliable power at reasonable prices and with efficient use of resources. Given these broad objectives, the following general yardsticks immediately lend themselves for sector performance evaluation purposes: 1. Economic efficiency which has the following short-term and long-term components: a. productive efficiency - short-run - long-run (least cost planning, innovation) b. allocative efficiency (short- and long-term). 2. Adequacy as measured by the degree of access and availability of power to consumers. 3. Affordability, fairness, and reasonableness of power prices. 4. Reliability, service quality and safety standards. In this context, some objectives of the Federal Power Act as stated therein, or its intentions as interpreted and clarified during the process of a number of court challenges, include: (1) "to protect power consumers against excessive prices," (2) "to establish just and reasonable rates," (3) "to allow only such rates as will prevent consumers from being charged unnecessary or illegal costs," (4) to bring about the production of electricity "at the lowest possible cost to the consumer in the long-run...," and (5) "to achieve the most efficient allocation of resources possible.:" Economic Efficiency An evaluation of the U.S. power sector with respect to economic efficiency yields somewhat mixed results. However, before proceeding to do this, it is instructive to briefly review the many dimensions of economic efficiency [26], [38]. Broadly speaking economic efficiency is synonymous with allocating and using resources in a way that most benefits society. Economic theory suggests that efficiency requires two conditions be achieved. First, production and delivery of power should occur at minimum cost. This corresponds to productive efficiency. Second, resources should be allocated where they have the highest benefit (value). This corresponds to allocative efficiency. - 13- Efficiency in electricity supply is obtained through a variety of operating and investment decisions [36]. Thus, short-turn productive efficiency requires purchasing fuel and other variable inputs at the lowest possible cost, dispatching plants on an economic basis, taking advantages of any opportunities to make economically beneficial purchases and sales from and to other utilities (exchange efficiency), proper maintenance, etc. In contrast. 'Jng-run productive efficiency requires least cost investment planning (capacity .nix, quantity, retirements, etc.) taking into account that key uncertainties exist and sufficient flexibility must be made available to avoid significant over- or under-capacity. Furthermore, long-term efficiency considerations must also concern themselves with the nature and the timeliness of process and product innovation related changes. Ailocative efficiency is influenced to a large extent by pricing policies, since prices generally play a significant role in consumer's consumption decisions. Thus, efficient prices should signal to consumers the economic cost of their purchase decision [37]. Balancing of short-run and loncj-run considerations is also important in efficient pricing decisions. This background helps to set the stage for the following evaluations of state and federal regulation vis-a-vis sector performance and efficiency. A detailed compilation, discussion and analysis of even the major deficiencies and issue areas is beyond the scope of this study. Instead the emphasis is on highlighting selected areas that could be of some relevance, for analyzing power sector efficiency and restructuring initiatives in the developing countries. In studying present inefficiency issues, it must be borne in mind that the underlying causes vary. Some arise largely due to the skewed ownership structure (i.e., size distribution) in the industry. Other inefficiencies are to be found in the retail markets. These inefficiencies appear to be ascribable to failures of state regulation. A third class of efficiency losses occur in wholesale power markets, with related "trickle down" implications into retail markets. Again, some of these are relatable to federal regulatory practice, and some to the industry structure itself. -14 - However, the following discussion suggests that inadequacies in state level PSC regulation appear to be the primary bottlenecks to achieving significant efficiency gains. This is because over 80 tu 90 percent of revenues for most IOUs are generated by transactions in retail markets; markets in which supply-demand interactions and utifl; incentives are shaped to a overwhelming extent by state PSC regulation. Long-Run Productive Efficiency Retail market regulation by state PSCs has historically focused unduly on the various facets of rate base/cost-of-service evaluation. Such proceedings invariably get bogged down in detail and controversy about specific line items in the rate base calculation and can be extremely time consuming. As a consequence, efficiency considerations have received little scrutiny until recently. In particular, PSCs have not generally concerned themselves with seriously monitoring and ensuring that utilities strive to achieve long-run productive- efficiency. Such inefficiencies can manifest themselves in several ways including: - sub-optimal scale of generating plant. - failure to develop least cost planning strategies taking into account real world uncertainties. - inadequate transmission capacity to maximally exploit exchange efficiency gains of any diversity -- in load, unit availability, maintenance, dispatch, reserve sharing etc. -- with neighboring systems. Sub-optimal scale of generating plant results when a utility is too small to fully realize economies of scale internally and yet builds plant independently. Exhibit 3-5 indicates the skewedness of the size distribution of IOU plant. The figures paint a worse picture than in reality, since they do not reflect holding company affiliations. Nevertheless, Exhibit 3-5 does reveal that a substantial number of utilities are perhaps too small to exploit scale economies on their own. Comparable data is not available on MUNY and other publicly owned systems but their addition to this data would adversely skew the distribution even further. The data suggests that with the exception of large holding companies (e.g., see Exhibit 3-2) substantial opportunities exist for efficiency gains through horizontal integration; by mergers, joint ownership of generating units, strengthening transmission tied, power pooling, etc. The realization of such - 15 - efficiency gains would subordinate state level regulation and rights to a broader regional level plar ig, coordination and regulating process. Such state preemption efforts are in direct conflict with those who vigorously espouse "state rights" and local control. EXHIBIT 3-5 SIZE DISTRIBUTION OF CLASS A AND B INVESTOR OWNED ELECTRIC UTILITIES, BY GENERATING CAPACITY, 1980 Generating Number of Total Capacity Capacity (MW) Operating Companies (Mm 0 23 0 Less than 1,000 72 21,682 1,001 to 2,000 33 44,648 2,001 to 4,000 39 117,004 4,001 to 6,000 13 67,053 6,001 to 8,000 9 62,200 Greater than 8,000 14 163,700 Total 203 476,287 Source: [32] Least cost planning failures have several dimensions. For example, critics note that New England Utilities should have turned to cheaper Canadian imports well before they did. In other instances, it has been noted that utilities have generally failed on their own initiative to seriously consider cost-effective options for "supplying" power. Indeed, in most instances even PSCs did not seriously get into the act until third party intervenors such as consumer interest groups, environmentalists, etc. mounted several challenges and forced such consideration of demand-side options and altemate energy sources in regulatory hearings. Finally, little attention has been focused on retiring economically obsolete plants. -16- Another type of least cost planning failure potentially stems from certain built-in features of rate base regulation. Some critics have suggested that rate base regulation provides a built-in incentive for over-capitalization (gold plating) and hence in compromising productive efficiency. The empirical validity of this (Averch-Johnson) hypothesis [5] has never been shown to hold conclusively. Furthermore, even if this had been true in the 1950's and 1960's the subsequent financial decline suffered by utilities since the 1970's, factors such as regulatory lag, and rate base (non) treatment of new plants have created just the opposite incentive. Most utilities at this point have no interest in initiating construction of a new major baseload plant addition because of the financial risks involved. This could lead in the future to inefficiencies arising from high operating cost but low capital cost plant in-place. Short-Run Productive Efficiency Exhibit 3-2 provides some indication of the extent of power pooling and coordination potential between utilities through short-term economy interchange and reliability support transactions. Critics have voiced the contention that considerable additional efficiency gains remain to be tapped as; that such gains need not necessarily rely on the setting up of highly integrated power pools with centralized unit commitment, economic dispatch and complex formulae for sharing of costs and costs. That even more informal economy exchange procedures such as those used by the Florida energy broker system can result in additional efficiency savings. There are no definitive analyses or hard and reliable estimates available of this incremental potential. What appears to be true however, is that existing interchanges are for the most part already utilizing all available transmission capacity in many areas of the country, e.g., "coal-by-wire" from the Southern system to Florida and from the Mid-west to the Eastern seaboard, from the Southwest into California, and hydro power from the Pacific Northwest into California and from Canada into the New England area. This is not to say that some additional potential does not exist. Indeed, this recognition underlies the Southwest bulk power experiment recently sponsored by FERC. This experiment was innovative in that it permitted participating utilities -- sellers, buyers, and any intermediate wheeling utility - to - 17 - enter into pricing arrangements based "what the market will bear" philosophy rather than the more rigid guidelines and caps imposed on such transactions under FERCs normal pricing provisions. A further departure in this direction towards deregulation of the short- term condition market was to provide added incentives for utilities to seek out such efficiency exchange transactions more aggressively by permitting stockholders of participating utilities to realize 25 percent of any benefits. As opposed to the traditional practice where any benefits are flowed through to ratepayers. The preliminary results from this experiment are reported to be encouraging [1]. Another reason that some potential remains untapped stems from the problem associated with the sheer numbers of small utilities. As the number of organizations increase it is inevitable that the diversity of interests, management styles, corporate cultures, and driving incentives make it difficult to develop formal and lasting contractual agreements that are required for such exchange to function smoothly. 4/ One example of such a problem is the preferential treatment - low interest loans and federal tax exemption -- accorded to publicly owned systems. This distortion in the financial cost of short-run power production in favor of public power provides an unfavorable competitive edge and investor owned utilities may be reluctant to therefore join in a pool with such companies. Inefficiencies in Resource Allocation With few exceptions, retail and wholesale transactions for firm service are priced based upon average embedded cost tariffs. 5/ In general, such ta :!fs (for all but the large users) neither reflect demand charges nor differentiate prices by time-of-use. This has resulted in short as well as long term inefficiencies that have implications for resource misallocation. Whereas quantitative estimates of the extent of such distortions are not available, obvious qualitative inferences have been made. Furthermore, the lack of consistent regulatory treatment of prices in the wholesale and retail power markets has also created the potential in certain situations for parties to engage in exchange transactions that will not enhance economic efficiency, but simply reallocate bene .s. -18- Availability of Electricity, Prices and Service Quality Most people would award an unqualffied success rating to sector performance measured by the first three criteria given at the beginning of this section. Electricity is also generally available to one and all with high reliability, quality and safety standards, although supply quality may be somewhat lower in rural areas. Furthermore, rates until recently have been low relative to incomes and affordable for the most part. The high saturation of electrical gadgets and electrification in the economy is a testimony to this affordability. However, whether rates have been non-discriminatory and just is a matter of opinion. This issue is discussed later in the section. 3.3 EFFECTS OF REGULATION AND OWNERSHIP PATTERNS In this section, we examine whether the pattern of regulation and ownership has had a significant positive or negative impact on utility performance. First, the existing regulatory background is described. The developmental history of the sector and evolution of the regulatory framework is summarized In Annex 1. State Regulation Today Regulation embodies legislative, legal and economic concepts. It centers around a quid-pro-quo. Utilities are believed to be "affected with a public interest" and "render an essential service." Therefore, in return for a monopoly franchise, regulation supposedly protects consumer interests as regards availability, rates, service quality, safety and efficiency; and the firm's interests as regard a fair rate-of-return on costs that are necesbary and prudently incurred in the provision of such service. Irrespective of the original intent, state level oversight today is predominantly occupied with rate base regulation under which the revenue requirements of a utility is determined using a process typHifed by the following equation. -19- RR = Cost-of-Service = E + D - T - (V-D)R where: RR = Revenue Requirement E = Operating Expenses (e.g., fuel, economy purchases, firm wholesale power purchase cost) u = Depreciation Expense T = Taxes V = Gross Value of Property Serving Public D = Accrued Depreciation (V-D) = Rate Base (net valuation of assets) R = Allowed ("Fair") Rate of Return State Public Service Commissions (PSCs) have jurisdiction over the retail rates ol all lOUs in their state. Further, in about 20 states the PSC also exercises limited control over MUNY/COOP retail andlor wholesale rates and/or certain practices as well. In many instar,ces a City Council has some oversight over a MUNY. TVA is totally self-regulating as are State Power Agencies. Federal Reaulation Today The Federal Energy Regulatory Commission (FERC) has jurisdiction over all inter-company sales of power ("sales-for-resale") whether inter- or intia- state. Two broad classes of transactions fall within this category: coordination (short-term economy exchange and reliability support) power transactions and wholesale transactions. The latter represent long term power purchase and sales contracts, typically between lOUs and MUNYs and COOPs. This market for power is generally referred to as the "requirements service market." FERC jurisdiction does not cover regulation of rates for power generated by COOPs and MUNYs. However, FERC jurisdiction extends to all wheeling rates (inter- and intra-state) though not to access related issues. Nationwide it is estimated that about ten percent of the total revenues of lOUs are under FERC regulation. However these average figures mask significant regional and company specific differences. -20- Regulatory Issues In the preceding discussion it should be apparent which inefficiencies represent primarily a failure of regulation - as practiced today - and which ones stem from the fact that such regulation is conducted at the state level rather than a regional or more geographically aggregate level. An example of an inefficiency that stems more from the fact that regulation is practiced at the state level is that it has often been subject to political pressures and locally organized special interest groups. Thus, in many cases this has led to inter-class subsidy in rates. This is not to deny that such forces would be non-existent if regulation were conducted on a regionwide or even national basis. However, as the geographical base expands chances are that there is a more effective system of checks and balances because of a wider diversity of players and interests. Furthermore, the opportunity set for achieving enhanced efficiency can be greatly widened as noted earlier. In contrast, an example of an inefficiency that results solely from the specific nature of rate base regulation is that the revenue requirements for a new unit addition are front-end loaded. This means that immediately following the completion of a large baseload plant and its introduction in rate base, rates jump up signfflcantly. As the plant Is depreciated over time this rate base and hence revenue requirements and rates decline. Thus, rates are high when capacity is in substantial excess of demand and vice versa. This is contrary to efficient price signalling. At present there is widespread disillusionment -- among all partles concerned -- about the ineffectiveness of regulation and the feeling that even if it had been effective so far that Tt is inadequate to ensure economic efticiency and related objectives in the emerging power markets that are characterized by significant uncertainty, higher energy prices, technological change, and increased competition. Potential prescriptions to cope with such a future range from developing a more effective regulatory framework to a variety of deregulation scenarios. 6/. Advocates of deregulation note that any form of regulation by its very nature has to be passive, inherently negative and after the fact. That striving for more effective regulation will lead primarily to more sophisticated gaming strategies on part of these being regulated and not necessarily higher efficiency levels. 7/ - 21 - Further there is a growing sentiment that in blocking entry and hence competition, regulation chokes innovation related improvements in economic efficiency. These costs of regulation are very hard to measure since they involve guessing what did not happen but could have resulted. Nevertheless, insights developed from examining the experiences with deregulation in some other sectors strongly suggests that price and entry controls have the effect of slowing product innovation and technological change by regulated firms. One indication of this effect is the very long depreciation schedules used by many regulated firms such as telephone companies and electric utilities. Absent competiion there is little incentive to depreciate plant faster than physically necessary. In contrast, firms in a dynamic competitive environment face a situation where these assets are likely to become economically obsolete well before they are physically obsolete. These firms -- i.e., stockholders--would have to absorb any losses associated with undepreciated assets that have to be retired in order to survive competition. It came as little surprise to telephone industry analysts that AT&T, during its reorganization wrote off about $5.2 billion in assets, in large part to reflect the reality of a reduction in book value associated with obsolete phone and network equipment. Telephone switching equipment is a case in point. Digital switching technology - especially "smart switches" that offer custom features such as call forwarding, international direct dialing, etc. - have been available for many years now. Under regulation, AT&T's plan was to convert all local exchanges by the year 20001 A look at AT&T's past also reveals that whereas three successive generations of increasingly sophisticated switches were developed between the 1920's and 1970's, there were still locations in the 1970's which had not yet benefited from such innovation. The inefficiency cost of such lags to customers are twofold. First, there are productive efficiency losses in that output is not being provided at least cost. In addition, consumers are deprived of new and improved products -- including unbundling, for which they may be willing to pay more or less and thus best meet their needs. A comparable case in point in the electric utility industry is the emergence of "smart metering" and microprocessor based systems that offer distributed control of selected circuits/end-uses at the customer premises. These devices make it possible to unbundle electricity service so that a consumer can tailor the reliability of service by end-use as he/she see best. However, widespread -22 - unbundling will also require utility investments and changes in utility planning and operation. Absent competitive pressures there may be little incentives to move in this direction or to simply "drag one's feet." Ownership Issues Public vs. Private Power The "public versus private power" debate continues today. Whereas over a century of experience has accumulated with different structures and key issues debated time and time again, no clear consensus or unique prescriptions have yet emerged as regards the preferred market and organizational structure. Nevertheless, the U.S. experience represents the most concrete information available and therefore can be of help in shaping a set of fundamental principles to be considered in any market restructuring initiatives. In this regard the U.S. experience as regards the Tennessee Valley Authority (TVA) is pertinent; especially since the TVA has served as a role model for many other countries. TVA was created by an Act of Congress in 1933 as an experiment to test the viability of an economic technocracy. It has now turned into a self- financing agency that must cover all power costs by power revenues. Thus, the modern TVA power system has been paid for entirely by its ratepayers. The TVA experiment since its very beginning has been marked by considerable controversy. Proponents point to its achievements in the forn of regional economic and social development through the pursuit of a dynamic promotional pricing policy, its impact in bringing down rates ,n neighboring regions, rural electrification, and a cornucopia of other benefits such as flood control, navigation, recreation, etc. [28], (61]. (see also Annex 1). On the other hand, critics [11 ] note that: 1. TVA's rates have been lower because of reasons such as: - its access for the longest time to cheap capital, and not having to make interest or principal repayments, - its access in recent years to below market financing from the Government, and - promotion of destructive coal strip-mining to reduce costs. 8/. - 23 - 2. Low rates may have led to inefficient allocation of resources. In the 1970's average household power consumption in the WVA region was double the national average (approximately 14,000 kWh versus 8,000 kWh). 3. Whereas TVA may have helped reduce rates in surrounding areas in its first decade by direct or threatened competition, substantial declines in private rates were already occurring because of the enactment of the Public Utilities Holding Companies Act which paved the way for more effective determination and hence regulation of private power production costs. 4. The hydropower developed by TVA created severe external costs in terms of the permanent flooding of homes, farmland, and natural habitat. These costs were not reflected in the cost benefit calculations. 5. Even after allocating 35 percent of dam costs to navigation and flood control, and not allowing for the opportunity cost of unproductive land, eleven of the original 20 TVA dams were nowhere near being cost effective when compared to the levelized cost of coal fired power. 9/ 6. Per capRta income growth in surrounding non-TVA areas has equalled or exceeded that in the TVA region, despite their being equal at the beginning of the TVA experiment. 7. Manufacturing employment grew more slowly in the TVA area than in surrounding non-TVA areas. 8. Rural electrfflcation progressed more slowly in the TVA region than in comparable surrounding areas. 9. TVA did not foresee that real price increases would have a considerable dampening effect on load growth. TVA's reserve margins are of the order of 40 percent. This figure does not reflect an additional 4,000 MW of deferred nuclear capacity on which 3 billion dollars have already been spent. As a separate matter, all of TVA's nuclear capacity has been shut down for quite some time now, for safety related improvements. Turning now to the private utilities, many have blamed them for their failure in proper demand forecasting, energy accounting and for failing to recognize the importance of own-price and cross-price elasticity effects that determine tuel choice behavior and consumption levels of electricity. This has led in part to tha present over capacity situation. However, the public power record is no better than that of private power in this regard. Further to the crPicisms aimed - 24 - at TVA, another example is the "WHOOPS fiasco" in the Pacific Northwest where public power agencies have through gross mismanagement spend billions of dollars and mothballed three nuclear power plants, and defaulted on their bond payments. Private utilities tend to dominate in the area of cogeneration, since an overwhelming fraction of this type of activity is in the service territory of private utilities. This aspect is discussed more fully in Section 4. In the area of energy conservation, much has been written about the large sums of money spent on informational programs, technical assistance, loans and grants for weatherization, etc. -- by large public agencies such as WVA and BPA. Unfortunately, there is little or no hard and reliable data to make valid evaluations and quantitative comparisons with private utility performance. It is generally recognized that TVA's efforts rank second to those of Pacific Gas & Electric Company (PG&E). However given that TVA's households (and for that matter BPA served PUD households) already consumed substantially more electricity than PG&E or other private utility served households, their performance in conservation does not begin to look as impressive. A more useful comparison of the relationship between ownership pattems and energy conservation is reported in a recent paper [64] which surveyed management and staff of "comparable" public and private utilities. - In California, the Los Angeles Department of Water and Power (LADWP) and Southern California Edison (SCE). - In Florida, the Jacksonville Electric Authority (JEA) and Tampa Electric Company (TECO). - In Texas, the City Public Service Board of San Antonio (CPS) and Dallas Power & Light (DPL). The following represents some of the major findings: 1. Whether voluntary or by arm-twisting, private utilities have done much more to encourage ccnservation and develop alternate energy sources (although it is not always clear that conservation targets are based on economic efficiency criteria). For example, SCE has aggressively adopted a conservation and renewable energy program. In contrast, LADWP has planned to meet its power needs by purchasing ownership into large central station plants in Utah, Nevada, and Arizona. - 25- 2. Neither the market nor regulation impose the same type of constraints on the MUNYs and IOUs. A LADWP executive is quoted as contemptuously dismissing SCE's plans for alternate energy sources: "ff the PUC tells them to make electricity from widgets, they must make electricity from widgets." 3. In Florida, TECO was able to generate over 80 percent of its power from low cost coal in 1982. In contrast, JEA was heavily dependent on oil with only 14 percent generation from coal. 4. In Texas, a city councilman noted of CPS that it had "no conservation goals." CPS has not been aggressive in seeking conservation, in part because it has excess capacity. 5. The survey results suggest that private companies are much more sensitive and responsive to government-regulation and public and media pressures than MUNYs. - 27 - 4. PURPA AND THE DEVELOPMENT OF COGENERATION AND INDEPENDENTLY OWNED POWER PRODUCTION 4.1 BACKGROUND Of all the legislative responses in the U.S. to the "energy crisis" of the 1970's, the Public Utilities Regulatory Policies Act (PURPA) of 1978 can perhaps be characterized as one of the most important recent energy policy initiatives, and one that is likely to have far reaching implications into the future. It is also a key ste,. that is of great potential interest to power sector policymakers in the developing countries. The competitive forces unleashed by PURPA if significantly unchecked in the future, signal a significant restructuring of the power sector market during the remainder of this century. Indeed this trend has already established a strong foothold and has gained considerable and growing momentum. Relevant portions of the PURPA legislation are overviewed in the following Section 4.2. To set the stage, however, the remainder of this introductory section presents a brief background discussion of the early rise. subsequent fall, and the recent resurgence of cogeneration and self-generation. Section 4.3 provides an assessment of the extent existing cogeneration as well as estimates of the projected economic potential and market penetration potential. Finally, Section 4.4 highlights the major outstanding issues and controversies surrounding PURPA as of this writing. Cogeneration: An Old Technology Rediscovered Energy conservation through the more efficient use of fuels can achieve significant energy savings without a necessary reduction in the consuinption of final goods. Cogeneration, which is the simultaneous production of electrical and thermal energy from a single on-site generation source, is a technology which exhibits such a potential for savings in total primary energy use. Conventional utility-operated power plants seldom achieve a total efficiency exceeding thirty-five to forty percent since much of the energy consumed in the process of generation is rejected as waste heat into the - 28 - atmosphere and streams - in the form of stack gases or as hot water discharges. In contrast, customer-owned or dispersed electric generating facilities are capable of recapturing nmuch of this otherwise wasted heat to generate process steam, to provide process heat, and to warm or cool buildings. In such facilities, it is not uncommon for the total efficiency of energy utilization to exceed eighty percent or more (Exhibit 4-1). Cogeneration is an old and proven practice. Between the late 1880's and eariy 1900's, oil- and gas-fired cogeneration technologies were widely used throughout Europe and the United States. Most industrial plants generated their own electric power with coal-fired boilers and steam turbine generators. In 1900, over 59 percent of total U.S. electric generating capacity was located at industrial sites (not necessarily cogenerators) (see Exhibit 4-2). Gradually, however, industry shifted from using its own cogeneration and generation facilities to purchasing utility generated power. By 1950, on-site industrial generating capacity accounted for only about 17 percent of total U.S. capacity, and by 1980 this figure had bottomed out to about 3 percent. The major factors that contributed to the decline in industrial cogeneration include: - availability of inexpensive (Exhibit 4.3) and reliable utility power; - declining block rates that provided a "quantity discount"; - increasing regulation over all forms of electric generation; - economies o. scale in central power generation; - industrial bias in favor of sales oriented investments rather than cost- cutting investments. - advances In boiler technology that provided low cost industrial "package boilers" - 29 - EXHIBIT 4-1 TYPICAL FUEL UTILIZATION EFFICIENCIES OF UTILITY GENERATION PLANTS AND COGENERATION PLANTS 35# output =<,; > °Ut :oXa S >w~~~~~~rzocosa 3% O.Heat 20 Othe l %.Blr lb Ot1her 'sociaxd , Losse s Asoiae ->8ses Ji~~~~~~Lskeedl - 30 - EXHIBIT 4-2 HISTORIC TRENDS IN INDUSTRY SELF GENERATION AND COGENERATION Regulation Emerges 1902 1912 1920 1930 1940 1950 1960 1970 1980 Industry Capacity (%) 59 53 35 21 22 17 10 5 3 Utility Capacity (%) 41 47 65 79 78 83 90 95 97 Total Installed Generating Capacity(%) 100 100 100 100 100 100 100 100 100 Source: [21] However, things appear to have come full circle. Events in the last decade created a climate that help shape a strong trend in key industries 10/ to return to cogeneration and self-generation. The primary motivation has been to combat the stiff increases in costs of production (Exhibit 4.3). In addition to fuel price escalation, the capital costs of cogeneration are now very favorable as well. Because of high inflation in the last decade, increased cost of regulatory compliance, bad project management, and other reasons, the total installed cost of baseload coal and nuclear plants is in the range of $1,5004,000 per kW. Typical investment costs for cogeneration systems on the other hand range between $500-2,000 per kW. 4.2 PERTINENT LEGISLATION Ongoing inquiries following the oil embargo revealed regulatory, economic, and constitutional barriers to any increase in cost-effective cogeneration as well as in customer owned cost-effective power production. To overcome these barriers, Congress enacted the Public Utility Regulatory Policies Act (PURPA) on November 8, 1978. 11/ PURPA aims to encourage the development of small power production (e.g., customer owned cogeneration, renewables based -31 - generation such as low head hydro, and solar, biomass based generation, and waste-to-energy conversion). In particular, Title II, Sections 201 and 210 of the Act directed the Federal Energy Regulatory Commission (FERC) to develop regulations to meet the objectives of PURPA. In response to PURPA, FERC rules 12/: - require electric utilities to purchase electricity from and sell power to small power producers. This obligation to purchase (also sometimes referred to as the interconnection rule) is applicable only to a "qualifying facility" (QF).13/ - establish guidelines to ensure that purchase power (buy-back) rates set by state regulatory bodies are just and reasonable. In particular, utilities must buy power from qualifying cogeneration facilities at their "avoided" cost of power generation, that is, at the cost the utility would pay if it produced the power itself or bought it from another power company; - mandate rates for power sales to QFs that are "just and reasonable and in the public interest," i.e., QFs are to be charged the same rates for power purchases that would apply if they were not OFs. - require electric utilities to sell supplementary, interruptible, maintenance, and any backup power as required by a OF (obligation to sell) at non-discriminatory rates; -32 - EXHIBIT 4-3 HISTORIC TRENDS IN NOMINAL ELECTRICITY PRICES kelwactVo nletrgC WZ;8~ ~ ~ ~~~~~~~17 1994. 15 - 10 - I\ 'oG ig9 194 ^7J) 19 - 33 - provide certain exemptions for QFs from some state and federal laws that normally govern utilities including those concerning the financial organization of the facility; 14/ during periods when demand for power is light and utilities are only using base load facilities, utilities may cease purchasing from qualified facilities. However, each facility must be notified prior to an occurrence of such conditions and tne cessation of purchase; - interconnection costs are to be reasonable, nondiscriminatory, and legitimately incurred and are to be reimbursed to the utility; and - the state regulatory authorities to implement rules for PURPA within one year (March 20, 1981). State and utility compliance of PURPA was very slow at first except in instances where the PSC was active and forward thinking (e.g., California, Wisconsin) or where third party interests were well organized and orchestrated. Many commissions were understaffed to take on this additional burden of developing the necessary rules and rates along FERC's guidelines. Several methodological hurdles -- perceived and real -- slowed the initial program. One of the most contentious issues initially centered around the interpretation of "avoided cost." Avoided energy costs are essentially defined by "system lambda" (short-run operating cost), appropriately adjusted for losses. However, little consensus emerged about the appropriate methodology for estimating avoided capacity cost that should be credited to a cogeneration. Since the avoided cost concept is identical to the notion of marginal cost, some of the very same issues resurfaced as they had a few years earlier in the context of the heated debates surrounding the issue of marginal cost pricing. There is no general agreement even today as to the method by which the capacity credit to the QF (i.e., the utility's avoided cost) should be estimated -- these now include the equivalent plant proxy method (peaker? coal plant? a weighted average of the two? power purchase cost?), the incremental revenue requirement method, the "forward-backward method," etc. Furthermore, many utilities favor a sharing of the avoided cost between themselves and the OF and do not want to give the full avoided cost benefit as a capacity credit to the OF. -34- The initial progress was further impeded by the antagonistic stance of most utilities to PURPA. With few exceptions, PURPA was viewed as a threat to their traditional monopoly markets. Most "dragged their feet" in the early stages by using a variety of tactics. Most extreme among these responses were legal challenges to rules promulgated by FERC to implement PURPA. Several regional challenges were mounted. In each case the courts eventually found in favor of FERC. The most well known and lengthy series of court reviews was comp'eted on May 16,1983, when the U.S. Supreme Court upheld Lb/: - Under the criterion that the rule was not "arbitrary, capricious, or abuse of discretion," FERC's full avoided cost pricing rule was within the range of permissible rates that Congress had established. - FERC's interconnection rule was not unconstitutional. With this decision, many of the remaining states and utilities that had adopted a "wait-and-see" attitude, began more serious efforts to implement PURPA. One point worth drawing attention is that resistance, lack of enthusiasm, or indifference to PURPA in instances where recalcitrance in some form has existed has not necessarily been limited to IOUs; many publicly owned systems have also felt threatened by the increased degree of market competitiveness potential introduced by PURPA. For example, critics note that the Los Angeles Department of Water & Power (LADW&P) has negotiated very few contracts for power from QFs; this in a state with enormous potential and where other utilities (e.g., SCE, PG&E) have signed hundreds of such contracts already. 16/ Indeed, the challenge to PURPA's constitutionality was fought all the way to the Supreme Court by an odd coalition of IOUs (American Electric Power and Service Corp., Consolidated Edison Corp.) and Colorado-Ute, one of the largest public power G&T cooperatives. Since public power systems are not generally regulated by state commissions, smaller QFs and independents served by them must overcome such hurdles by resorting to potentially complex and expensive and time-consuming litigation in courts or by representation to FERC. - 35 - 4.3 IMPACTS: PRESENT AND FUTURE POTENTIAL Exhibit 4-4 presents estimates of existing cogeneration capacity, future economic potential, and market penetration potential. Present installations (including those under construction at the beginning of 1986) are estimated at 20,000 MW, about 3% of the total installed generating capacity in the nation. Whereas this represents no increase from the year 1980 (Exhibit 4-2), it must be pointed out that legal challenges to PURPA and the initial inertia to the removal of barriers to QFs consumed several years after PURPA was passed in 1978. 17/ Existing econornic potential is estimated around 43,000 MW with an additional 48,000 MW growth based potential at existing plants and/or new plants. Available market penetration estimates by the year 2000 indicate potential in the 40 to 60 thousand MW range. These estimates for the industrial sector derive largely from opportunities in specific manufacturing categories, chemicals, petroleum refining, paper and pulp, food processing, primary metals, textiles, wool and lumber, and enhanced oil recovery. Reliable estimates of potential in the commercial, institutional, and residential sectors are not available. However, the general feeling is that substantial potential exists in these sectors, well beyond the numbers indicated in Exhibit 4-4. The final outcome will depend upon the degree of success achieved -- in terms of date of commercial availability and capital costs - in the rapidly developing field of gas-fired, packaged cogeneration systems that can be bought "off-the-shelf." Many in the gas industry 18/ are aggressively promoting the development, demonstration, and commercialization of such systems. These activities are typically targeted for hospitals, hotels, restaurants, supermarkets, and schools. 19/ Attention is also being focused on the personal (micro) cogeneration systems in the 6-15 kw range for homes, small businesses, and multiple apartment buildings. - 36 - EXHIBIT 4-4 EXISTING CAPACITY AND PROJECTED POTENTIAL (COGENERATION ONLY: Does not Include Self Generation) FPeut1y FBdstig Sed InzutaIell &cmlc F Iut Type Fotertd P il Potetatl Pom,ial itS 1. idt.a1 2D,WOo Yd 43,00 NW at tba 48,000F MI 40,000*, 63Z gm tLwbne 3,0000 luaet ttwu 3200 60,0D MI 272 stan turb±ns ads" Pln by MOD Ia IC evg1e 2. Law CdaL N/A N/A N/A 1,400 MI hutlttot and luaW biUd±tta 3. Smal &rdal o 150 system WA WA 1988: 15 K001W o 15 f 4,00 wilts 2)0: 40,000 umtt 4,000 Mi1 4. Pefoel Systm NA NWA NA N/A Tstalled cost s a. 6-1 redailat 10-13K, for 1W b. 15 KIt re/a sys an 2)K for 15 W system. Paybck 2-1/2 aran Soiwo: sed upon dam repote In X eimt1o RBPort, Eleetric Utlity Wk, Cqmtiolan World, aid Elactrial World. - 37 - Thus, the best available data at present indicates market penetration of 40-60 thousand MW of industrial cogeneration by the year 2000 plus several thousands of megawatts, as yet not carefully estimated, in the commercial and residential sector. 20/ On a nationwide basis, this would represent over 10 percent of today's installed capacity. Examination of the regional potential reveals a considerable degree of concentration in certain areas of the country. For example, nearly 60 percent of the 43,000 MW4 of economic potential at existing industrial planWs (Exhibit 4-4) is concentrated in ten states. 21/ Estimates of the potential for all QF power (cogeneration and small power production) are much more dramatic when presented in the context of electric utility service territories. For certain utilities in the ten states referred to above, this potential is so large as to possibly defer the need for any utility built plant well into the early part of the 21st century. A case in point is the Pacific Gas & Electric Co. (PG&E), the nation's largest utility service in Northern and Central Calf-ornia. Exhibit 4-5 summarizes the amount of capacity by type of QF that is presently operational (approximately 1,100 MW) under signed contracts (7,000 MW), and under active consideration as of the third quarter of 1985 (2,500 MW). These figures reflect only the potential that project owners see as being economic as of now. More OF supplied capacity could and would m%:.rialize in later years beyond the 11,000 or so megawatts represented in Exhibit 4-5. Several other utilities (e.g., San Diego Gas & Electric, Northeast utilities, Houston Ught & Power, Texas Utilities Co., to name just a few) face a market with substantial supplies of OF power potentially available. Some are being more aggressive in seeking out these supplies as a substitute for building central station plant. 22/ But the "writing on the wall" is very clearly that there is little or no need for additional utility capacity in the foreseeable future in many of these and other utility service territories based upon present extrapolations. 23/ 4.4 SOME POLICY :SSUES If the performance of PURPA were to be measured by the amount of OF generated power that it has encouraged, it would be rated a "success" by most neutral observers. However, a closer look at the situation reveals that other factors besides PURPA have had a significant impact upon this development. - 38 - EXHIBIT 4-5 PG&E: SUMMARY OF COGENERATION AND SMALL POWER PRODUCTION PROJECTS Projects Projects Projects With Under Active Operational in Signed Contracts Consideration 3rd Quarter 1985 3rd Quarter 1985 3rd ouarter 1985 Project Type No kU No kW No kW Cogeneration 75 462,525 111 3,106,790 44 1,737,815 to 1,828,315 Solid Waste/Blo&ass 23 57,103 53 1,024,985 10 187,620 Geo haernal 2 80,700 10 94,200 0 0 solar (greater than 1 6,900 1 9,100 1 1,000 100 kW) Solar (100 kW or less) 6 46 1 3 1 2 Wind (greater than 30 362,120 36 1,986,520 3 48,750 100 kW) Wind (100 kW or less) 102 1,071 0 0 2 21 Hydroelectric 46 137,389 170 822,736 35 355,250 (greater than 100 kW) Hydroelectric (100 kW 20 924 4 350 5 237 or less) Other 2 1,100 4 24,800 0 0 Subtotal 30I,109,878 kW 388 7,069,484 101 2,330,695 to 2,421,245 PG&6 Projects 3 6,203 kW 0 0 18 192,300 Total 310 1,116 KW 388 7,069 MW 119 2,500 MW Source: 'Cogeneration and Small Power Production Quarterly Report," Third Quarter 1985, Pacific Gas & Electric Co., San Francisco. -39- In particular generous tax credits and other subsidies have had a measurable impact on OF penetration, historically. Particularly in the area of renewable energy based technologies, many investments were made primarily for their tax benefits. The recent expiration of many of these investment credits and tax benefits will certainly put a severe damper on the extent of market penetration of renewable energy based QFs in the coming years. In the case of cogenerating QFs, the elimination of tax benefits will slow down their pace of future development significantly, but nevertheless future levels are still expected to be substantial, (barring drastic fuel price changes). Critics are also concerned, and correctly so, about the efficiency implication of PlURPA. The major efficiency (and equity) related Issues include: - requirements in certain jurisdictions for utilities to purchase Qf power at rates in excess of the purchasing utilities true avoided cost - impacts of poor performance by QF's: reliability, dispatchability maintenance scheduling etc.--on utilities and ratepayers - in equity in risk sharing by allowing QFs lock-in long term contracts with guaranteed minimum payments - fuel use implications of QFs - restrictions on utility ownership of Ofs. Overpayment of capacity credits has resulted in some states where special interest groups, the legislature, or the PSC itself were instrumental in forcing the establishment of such rates. These violations in implementation of the intent of PURPA and the economic principles underlying the avoided cost concept have resulted in stimulating more OF development than is economic. In essence, the ratepayers of affected utilities are subsidizing QFs. In some states QFs have been accorded a privileged status by virtue of the fact that utilities are forced to offer long-term contracts that stipulate a guaranteed minimum payment. QFs contend that such guarantees are needed to obtain the necessary project financing. However, critics rightly point out that in no other business areas, do businessmen have the luxury of entering into risk-free, long-term contracts with p ice guarantees. Why should risks be transferred to ratepayers through such long-term guarantees? - 40 - Factors such as these have resulted in over-supply of OF power in affected areas. For example, Houston Light & Power's own generating units will provide adequate capacity through the remainder of this decade. Yet they are presently forced to purchase 3,000 MW of OF power and this amount is projected to increase to 5,700 MW over the next five years [25]. In April of this year the California PUC finally suspended "Standard Offer No. 4" which provided long-term guaranteed contracts after more than 15,000 MW of OF power were offered and contracted for and it became clear that over 7,000 MW additional were under consideration. Initial estimates, prior to this offer had pegged the California cogeneration potential to be in the 2,000 MW range by the year 2000. 24/ Some other states are also beginning to take a closer look at any such excesses that may have been committed. A common thread underlying many corrective measures that are being mentioned is the "level playing field" concept. These measures include: - spot pricing - use of a bidding/auctioning process for new resource development - according of avoided cost treatment to utility plants as well as Spot -- i.e., real time -- pricing is akin to short run marginal cost pricing where the prices essentially reflect system lambda plus losses during non-peak periods [8], [9]. However, when the system is under stress, a generation and network quality of supply cost (i.e., shortage cost) component can raise the spot price. Spot pricing is viewed by some utilities as a correct and fair way of compensating OFs. 25/ Indeed this was a major factor in the Caiifornia Energy Commission's (CEC) recent siting approval of a 65 MW cogeneration plant at an IBM facility in San Jose, California, even though there is an oversupply of OF power at present. The proposed 10 year agreement between IBM and PG&E represents a milestone for spot pricing which is being implemented as "post-facto pricing on an hourly basis to reflect actual experienced marginal cost." 26/ Another vision of the level playing field concept is the bidding/auctioning proposal of the Massachusetts PSC; 27/ that has also been suggested in Texas as well as embraced by PG&E and supported by staff at the - 41 - California PUC. Whereas specffic aspects vary, the general idea here is to adopt a process of the following type. Periodically a utility would determine the need for additional resources, e.g., amount, reliability, dispatchability, baseload, peaking, etc. It would issue a "request for proposal" for such services. Potential OFs would then bid against each other to supply their need. To protect ratepayers the utility would not accept any bids above its avoided cost. On the downside, conceivably, a OF may be paid a price below the utility's incremental cost. Essentially the extent of OF competition would determine this level. Any unmet resource needs would be built by the utility. 28/ If competition is "good for the goose" it must be "good for the gander" as well. Certain parties in California have used this rationale to go one step further by suggesting a total bypass of rate base treatment for new utility plant. They argue that such plant -- e.g., PG&E's Diablo Canyon nuclear power plant -- be accorded the same rate treatment as another qualifying facility. Many in the industry were surprised when PG&E announced its readiness to negotiate such an unconventional deal which would have marked a major milestone in the path towards deregulation of all new generation. 29/ Some PURPA problems arise from insufficient incentives for utilities to promote QF development. Whereas any QF supply represents a potential competitive threat, certain incentives may go a long way in changing utility attitudes to such threats. Prominent among such measures are: Instead of full avoided cost payments to QFs, the utility be allowed to retain some portion, to be then split between ratepayers and stockholders. - Remove the existing 50 percent cap on utility ownership of a QF facility. Finally, wheeling OF power remains the most thorny and complex issue that cuts to the very heart of the industry's concerns and fears. The two major aspects of wheeling are access and pricing. The wheeling issue arises in situations where OF supplies exceed the local utility's needs and hence any excess must be wheeled to other systems or to another plant operated by the owners of the QF. 30/ More aggressive QFs are interested in going one step further and having their excess power wheeled directly to another retail end-user, thus engaging in direct competitior. with IOUs. Whereas this interest represents a minority segment, it is one that is growing. 31/ - 42 - Many utilities, e.g., in Texas, California, and Florida are at present wheeling OF power for situations of the former type, wnen Idle transmission capacity is available. Some other states are moving towards this direction. This is enabling independent power producers to compete effectively with utility generating capacity. The major problem looming oni the horizon relates to the pricing of such transactions. Pricing transmission has been aptly characterized as "staggeringly difficult" by a FERC commissioner. 32/ Part of the difficulty arises because electricity flows do not confirm to utility lines or state boundaries; they follow Kirchoff's law and impact all other systems that are even distantly connected to the network. A quick resolution of this wheeling issue appears unlikely. - 44 - 5. THE EMERGING COMPETMVE PHILOSOPHY: CONSUMER CHOICE, DEREGULATION, AND PRIVATIZATION The electricity utility industry is in a stage of transition. There are several forces at work which have brought about the recent changes and whose interplay will further shape a potentially significant restructuring of the power markets tomorrow. The ongoing dynamics are being driven by what can perhaps be best characterized as competitive forces. These competitive forces are an outgrowth of altered economic conditions, technological advances and PURPA legislation. These forces take on added significance and strength in an environment today that is marked by a strong prevailing sentiment - in signNifcant segments of political, regulatory, industry and consumer circles -- in favor of consumer choice, competition, deregulation, and privatization. 5.1 RECENT DEVELOPMENTS More specifically, customers of utilities with large amounts of oil and gas fired generation experienced sharp rises in electricity rates in the last decade following the Arab oil embargo. In other instances "rate shock" was either related to or further compounded by the costs associated with nuclear power plant construction programs that many utilities had embarked upon years earlier. With few exceptions, these programs experienced astronomical cost overruns. Whereas the specific set of circumstances and reasons vary in each case, broadly speaking, cost overruns resulted from a combination of factors: high inflation, frequent and costly design changes and/or modifications midstream to ensure compliance with regulations related to health, safety and the environment, and mismanagment. Exacerbating the problems was the fact that because of conservation triggered by energy price increases as well as a slow economy, the fixed costs of excess power plant capacity must be recovered from a smaller consumption base. Frustration and discontent abounds among all customer groups. Residential users in particular feel that they have little or no control over bills. 33/ Heightened consumer awareness has translated into more aggressive interventions during rate hearings and hence more regulatory scrutiny than ever. - 45 - As a consequence, some far thinking utilities have started looking for some new solutions. Most innovative among these ideas is that of unbundling in terms of service reliability and/or end-use. Options being considered for implementing this concept are demand-subscription rates, spot pricing, and value- based pricing. The motivation for unbundling comes from, among other things, customer surveys which indicate that a large fraction of households may be willing to accept lower service reliability in exchange for a bill reduction. On the other hand,some Industrial and commercial users prefer service reliability higher than available today and are willing-to-pay a premium for it. 34/ Unbundling electricity services help to increase economic efficiency by a closer matching of customer needs and preferences with service characteristics. In addition, it should increase customer satisfaction by virtue of the fact that users will have a choice of alternatives and therefore cannot justifiably complain that they are captives with no alternatives. Unbundling by end-use can also increase economic efficiency, by increasing competition in residential end-uses such as space conditioning, water heating and cooking; since these applications can also be served by natural gas. Indeed competition from natural gas utilities for this market is increasing. For example, gas utilities are pushing the high efficiency gas furnace as an alternative to the electric heat pump in the heating market. A recent commercial of the Gas Company of Kansas declared "The fact is, 41 cents of gas can provide as much heat as $1 worth of electricity," and the electric utility in the region labelled this as "unjust, irresponsible and detrimental to the public interest" (EUW, February 14, 1983). IndustrL.l users face unique problems of their own. For example, electricity-intensive industrial users face pressures to stay cost-competitive in the.r own markets. Some other industries, e.g., "high-tech" are greatly dissatisfied with the quality and reliability of service. This customer segment is flexing is newly found market power. This power is sustained by several economic alternatives available to them including: - cogeneration - self-generation - inter-fuel substitution (primarily natural gas) - using a specific plant as a "swing (or optional) plant" - relocation In addition, bolstered by PURPA, large users are demanding that they be allowed to engage in "rate shopping." This market power is real and is being exercised increasingly, with results that can only be found in competitive markets. -46- An examination of rate negotiations in recent years reveals innumerable examples where, for example, an industrial customer has reduced its electricity cost by actually resorting to one of the options listed above or forced the utility to renegotiate a more favorable rate based upon the threat to exercise such an option. Some examples are: - Pacffic Power and Light's "on-site generation displacement rate" lured 11 MW of industrial I ad off self-generation (EUW, September 3,1984). - "Kennecott Copper Corporation takes up Utah P&L offer for cut-rate power, and shuts down its 17.5 MW unit" (EUW, April 4, 1983). - Lukens Steel Company's attempt to switch high cost service from Philadelphia Electric Co. (PECO) to lower cost service from Pennsylvania Power and Light eventually resulted in rate discounts from PECO. - Actual switching of suppliers has bee done in many instances, e.g., the Stauffer Chemical factory in Lot iana switched from Gulf States Utilities to lower cost service offered by the MUNY in the city of Plaquemine. = "PG&E will lower its industrial rates to cu: customer loss to cogeneration," (Cogeneration Report, March 28, 1986). - "KG&E Steers Its Biggest Customer Away From Cogeneration With 'Unique" Pact" (EUW, December 16, 1985, and EUW, February 24, 1986). - AP&L Offer Seeks to Stem Cogeneration By Duplicating Project's Cost Benefits" (EUW, April 14,1986). This list of cases, exemplifying the competitive pressures brought about by the market power of larger users in the form of rate shopping, fuel substitution, self generation, etc., is almost endless. On occasion this competition also pits one utility against another. This occurs not only in the form of fringe area competition; 35/ but franchise competition as well, for example, in instances where a town attempts to end a utility's franchise by a buy out. 36/ Economic alternatives for commercial users arc also emerging and this will increasingly give them the market power as well as to negotiate competitive rates. Such competitive pressures come from: - Energy service companies that design and install energy management control systems, high efficiency HVAC and lighting equipment, etc. In some instances such companies also provide a guaranteed minimum bill savings to the client in exchange for a - 47 - - Emergence of off-the-shelf mid-size cogeneration systems, and thermal cool storage. 37/ Cogeneration systems and thermal storage as a threatening competitive alternative are already being considered very seriously by many utilities. This stems from the fact that often commercial tariffs are the highest for this customer class, and in particular the demand charge is very stiff. In these cases especially, the optimal sizing of cogenerator and storage systems is driven in part by peak shaving benefits. As a response, many utilities are attempting to develop "cogeneration displacement rates" for this customer class as well. Another signal to utilities that the rules-of-the-game are being rewritten, defacto and in the middle of the game is the rate treatment 38/ accorded to recently completed plants. "Phase-ins," "inventorying" and other forms of disallowances are a clear message that the historical relationship as regards risk sharing and return-on-investment are no longer acceptable. In particular, it is axiomatic in the fina, scial world that rewards follow risk. Traditionally the utility business was considered to be a low risk business since ratepayers shouldered any risk. The recent developments and regulatory decisions noted above clearly indicate that utilities face increased risk as regards to cost-to-completion, time-to-completion, "prudency determination" and rate- treatment accorded to any facilities that they build in the future. Furthermore, the expectation also seems to be that the utility is responsible for effectively coping with the new era of pronounced uncertainty in load growth, fuel prices, etc. 39/ These expectations are only rationally consistent with a competitive market model in which suppliers face all the risks and hence operate under a symmetrical relationship between risk and reward, that is not present in the power market structure today. In partijular, flexible pricing in competitive markets implies that prices are depressed when demand is slack. On the other hand, tight markets present opportunities for higher than normal returns. Unfortunately, this type of symmetry is generally not permitted in the retail power markets. 40/ 5.2 PRIVATIZATION AND DEREGULATION OPTIONS Another "cure" prescribed for today's ills is to develop more effective regulation. This was discussed earlier in Section 3. Others have called for "deregulation" and "privatization." These prescriptions seek to greatly accelerate the established momentum and trend towards more competition and higher economic efficiency. - 48 - Privatization refers to the budget initiatives of the present administration 41/, which calls for the sell-off of the five PMAs (identified in Exhibit 3-1). This would accomplish two objectives; deficit reduction and the potential for achieving increased economic efficiency. The primary functions of the five PMAs are to (1) market and transmit all surplus hydroelectric power generated at designated federal dams, (2) to give preference in surplus power rates to public power systems (i.e., MUNYs, COOPs), (3) to encourage widespread use of electricity, and (4) to market power at the lowest possible rates that are sufficient to recover annual operating costs, debt service (interest payments), and return of federal government's capital investment within 50 years. The PMAs have succeeded in achieving the first three objectives. However, performance as regards compliance of the fourth objective is dismal. Permitte tariffs are so low as to barely cover annual operating cost. Repayment of principal is sporadic. For example, by year end 1984 Administration (BPA) had only paid back about 8 percent of the cumulative federal investment. 42/ Since the PMAs are not forced to adhere to a fixed amortization schedule there is a lack of financial discipline. PMA consumers are being heavily subsidized by all federal taxpayers by virtue of the fact that PMAs are charged interest rates in debt service that are substantially below market rates. This implies misallocation of energy and environmental resources. 43/ As a consequence of such mismanagement, economic efficiency losses are staggering. For example, OMB estimates [57] indicates that the average price of the Western Area Power Administration (WAPA) supplied power is 10 mills per kilowatt hour, compared to the marginal cost of 47 mills/kWh in the private sector. Senator Howard Metzenbaum has noted that the average cost of power marketed from Hoover Dam is a half cent per kilowatt hour, whereas the average cost of energy in other parts of the Southwest is 2 to 7 cents per kilowatt hour. 44/ Such gross subsidies have resulted in over consumption of electricity through, for example, higher saturation of electric space heating. Privatization initiatives call for a phased divestiture of the PMAs. Potential buyers of stock include COOPs, MUNYs, lOUs, private investors and consumers in those regions. Encouraging participation of the latter can be important especially if PMA assets are sold on a market based value and not an original cost basis as is proposed in the budget. As shareholder participants, consumers can choose for themselves whether they prefer to pay higher rates and therefore receive high dividends as well, or would like low rates and hence low dividends. -49 - Finally, there are a plethora of "deregulation proposals" that are being discussed for the purposes of reforming the industry and increasing competition. A detailed discussion and analysis of the various alternatives is well beyond the scope of this report. Broadly spriking, these initiatives imply some level of separation of the three functions of generation. One form of deregulation -- that is already an emerging phenomenon -- would occur in the wholesale market in the form of privately owned generating- companies (GENCOs). Such companies would operate outside the traditional boundaries of retail rate base regulation. Furthermore, from the GENCO's point of view FERC regulation represents by far the lesser of two evils -- state and federal regulation. GENCO stockholders would absorb any risks associated with plant completion, plant cost as well as the market risk associated with future regimes. Since GENCOs would shoulder all the market and non-market risks as opposed to ratepayers, they would have to be allowed to earn a commensurately higher expected return than regulated utilities. A case in point is Eas.ern Utilities Associates (EUA). EUA represents a consortium of investors who have bought a 10 percent stake in the Seabrook nuclear power plant that is yet to be completed. Since EUA will bear all the risks concerned, all the parties involved -- EUA, FERC -- have agreed that electricity sales would be made at market based rates for four years with a price cap. A final order is expected shortly which in effect would permit EUA a higher expected allowable rate of return than normal. EUA represents an example of a GENCO that resulted as a result of opportunistic buying. 45/ However, the case of the proposed joint venture of Public Service Company of New Mexico (PNM), Bechtel Corporation, General Electric, and the Navajo Nation to build and operate a 2,000 MW coal plant, represents a ground-up effort to establish a GENCO. Plans for this project are moving ahead as of this writing. The presence of GENCOs will increase the level of competition in the wholesale power market. One proposal for deregulation calls for further increase in competition in the coordination transactions portion of this market - i.e., economy energy, emergency energy, unit power sales, and short-term power -- by eliminating all FERC jurisdiction over such transactions. Whereas theory offers many benefits from this type of deregulation, the extent of any benefits beyond those already being achieved, is highly debatable. Some argue, perhaps righfully so, that simply increasing the incentive for utilities to participate in such transactions, e.g., by permitting stockholders to share some portion of the benefits, would go much further in enhancing efficiency. - 50 - Deregulation proposals essentially vary in the level of vertical disintegration envisaged. In the models just discussed, the generation functiun would be deregulated at the wholesale level. However, T&D would function essentially as at present. Another category of proposals envision further separation of T&D by the formation of regional companies that own all bulk power transmission facilities. In one version the distribution function would continue to be performed as today by lOUs, MUNYs, PUDs. Further, access to the transmission grid and pricing would be assured on a non-discriminatory basis. This scenario is sometimes referred to as the "phototype deregulation model" [22], [42]. Another version of the prototype model would involve total separation, with distribution as an exclusive monopoly franchise function. 46/ These franchise operators (potentially including MUNYs and COOPs) would be buyers in the market and would negotiate directly with one or more suppliers. The regional transmission entity would serve in a common carrier status, as is being encouraged by FERC in the natural gas industry. 47/ In other variationsof this model, the regional transmission entity would have a more substantive integrative role in that it would assume authority for purchasing and suplying least cost power with adequate reliability. Thus, it would perform key coordination functions -- operation and planning -- such as energy brokering, economic dispatch, preparing long range forecasts of demand and supply, etc. A number of market organizational and pricing schemes have been discussed within the context of these scenarios. Some emphasize a system of organization based upon long-term contracts between buyers and sellers, with short-term coordination transactions to capture exchange efficiencies, essentially in the manner the market functions at present. Others (e.g. [8]) put much more emphasis on a short-term spot pricing approach under which the regional broker would announce on a real time basis the requisite prices that will clear the market.48/ For the most part, the implications of these and other deregulation proposals have not been examined in even a cursory manner. Indeed, most "proposals" are only partially defined concepts. One must more concretely specify a list of technical, institutional, regulatory, market related and economic and financial parameters before an objective and comprehensive evaluation can be undertaken.49/ The importance of a holistic approach to evaluating alternate deregulation proposals cannot be overemphasized. Deregulatory tinkering piecemeal of an otherwise fully regulated market will invariably trigger consequences in other parts of the market. Thus, such initiatives which on surface appear to be desirable may in reality simply result in shifting the cost and risk burden to other market segments. A number of the "wheeling" and "rate shopping" proposals by QFs, large industrials, MUNYs and COOPs illustrate this point. - 51 - However, before the grid can be opened up to these interests, careful consideration must be simultaneously given to a host of technical realities, regulatory factors and changes required, including any special problems imposed by dual (state and federal) regulation, the obligation to serve requirement, pricing of backup, supplementary and standby power, etc. As an example, the privilege of rate shopping should imply that such loads cannot be treated on a firm requirements basis. In other words, provision of competitive entry to the grid has to be a two-edged sword. On the one hand, it offers potential opportunities for obtaining cheaper power or higher prices for sales. On the other hand, rate shopping increases the risk that supplies may not be forthcoming when required or more likely that the price is not right. Conceivably some of these customers might still elect to have part of their load served on a long-term requirements basis. This is somewhat akin to buyers and sellers in oil markets, for example, who must decide what portion of their needs they want to contract on a long term supply basis and what portion of their demand they are willing-to-risk on the spot market. This market organization resembles somewhat the existing Swedish model (see Section 6) where major wholesale suppliers and buyers of power -- e.g., utilities, industrials, MUNYs, COOPs, independently owned power producers -- buy access rights for a prespecified amount of transmission capacity and period (e.g., 5 years). Cancellations are not permitted. However, excess capacity can be sold back on the spot market. In addition, severe penalties are imposed if the reservation capacity is exceeded. The point here is not so much that the Swedish model is the preferred solution. Rather, deregulation proposals must be acted upon only after a fairly complete specification and evaluation of all the major interactive linkages in the market. The distributive and equity impacts -- costs and benefits -- of such proposals on dffferent regions, and across interest groups and customer classes, are likely to be very substantial. It is safe to say, therefore, that any form of deregulation, ff it occurs at all, will be evolutionary in nature, after it is established through actual experimentation, that such a change is supportable by a substantial Kf not majority segment of the collection of divergent interests at stake. In the near to mid-term future it appears likely that increased competition and economic efficiency gains can be reasonably expected to be achieved in the wholesale power (non-requirements) markets through GENCOs, formation of companies that operate and jointly sell steam and electricity, 50/ wheeling of excess QF power, a movement towards market based flexible pricing especially for new facilities 51/ and perhaps the information of more regional energy brokerage schemes 52/. Retail markets are also likely to encounter increased pressures to move further towards more flexible and market responsive pricing, e.g., value based pricing, unbundling, spot pricing, demand subscription. -51-A 6. IMPLICATIONS OF U.S. EXPERIENCE FOR POWER SECTOR EFFICIENCY AND RESTRUCTURING IN DEVELOPING COUNTRIES In the U.S., as in other countries, the question of how best to organize the power sector continues to fuel an ongoing debate which began when electricity was first generated commercially. Despite the fact that over a century of experience has accumulated with this sector, answers to the basic question still do not command a general consensus. Although the U.S. is one of the most market-oriented economies in the world, and many of the favourable market conditions taken for granted there do not exist in most developing countries, the accumulated body of U.S. power sector experience does provide useful insights. The objective of this section is to highlight the general implications of the U.S. experience for developing country efficiency and restructuring initiatives. It is beyond the scope of this report to provide any specific prescriptions. Such detailed analysis will generally vary from country to country and must be conditioned by prevailing realities. To illustrate this, we begin by posing the basic question: What is the best (i.e., most effective) way to organize and structure the power sector for performance? The discussion of any policy initiatives for restructuring cannot be formulated in a vacuum. It must be made within the context of a reasonably wel! defined set of goals and standards to enable comparative evaluation of alternate strategies. National goals, for the power sector may include one or more of the following [40]: 1. Maximizing growth and output (economic efficiency) - productive efficiency - allocative efficiency 2. Meeting socioeconomic needs - improve the overall quality of life by providing adequate electricity at reasonable prices - provision of basic needs of the poor - regional and sectoral growth 3. National security and self-reliance 4. Protection of the environment. - 52 - In addition to these national objectives that generally reflect the prevailing ideology, economic structure, institutional framework, and sociopolitical considerations, several other considerations that would be important in a country-specific context, include: 1. Size of country, demographics, and geography 2. Resource base (manpower, technical expertise, energy resources, present state of power sector, etc.) 3. Stage of the country in the developmental Ife cycle 4. Fxistence of, and access to capital markets These and other factors could conceivably render some of the options discussed in this section irrelevant or infeasible in the near and possibly even the long-term. This determination can only be made on a country specific study basis. The list of national goals mentioned earlier is often a useful starting point, and it is important to begin by clearly articulating a set of such goals. For example, if 'public ownership" is a (highly) desired end in itself, then much of the current debate on public vs. private power power systems becomes less relevant. But even under such limiting circumstances, methods of strengthening competitive forces anu promoting market incentives to improve power sector efficiency and performance, that were effective in the U.S., might be adapted for use in the developing countries, where appropriate. Ideology, as another example, might totally subordinate economic efficiency considerations to "higher ends' such as quality of lIfe, national security, justice for all, etc. Many of the insights provided by this paper would be of very limited appeal in such instances. Generally speaking, the 100 years of U.S. power sector experience suggests the following: 1. The structure of the power sector should be such as to induce the type of performance-oriented discipline that is typified by a competitive market structure. 2. Regulation as a means for enhancing economic performance has many limitations. This suggests that regulation by regulatory bodies be limited as far as possible to only those aspects of the sector which cannot be adequately self-regulated by competitive forces. 3. To the extent regulation is necessary, it should be applied to provide the necessary control of private as well as public power. Experience indicates that when resources are allocated by individuals who answer neither to the marketplace nor the general public, the potential for - 53- mismanagement and gross misallocation of resources is great, whether such decision makers are in the private sector or the public sector. 4. To the extent some regulation is required, it should help to provide broad policy guidelines, and be concerned mostly with achieving overall results consistent with such policies. It should not seek to control every aspect of a utility's planning and operations. Instead, it should provide flexible but clear and unambiguous signals that impose a minimum of interference on the utility managers. We note at this point that the desirability of strengthening competitive and market forces does not necessarily imply a completely free market organization or total privatization; nor does it preclude public ownership. Indeed, the fundamental tension between public vs. private ownership is more apparent than real given the realization that in the long-run neither a public nor a private utility can provide adequate and efficient service unless it is financially healthy. On the other hand, even a privately owned utility cannot maximize profit in the long-run without providing adequate service and at prices that the public finds reasonable. 53/ Therefore, if cne accepts the basic proposition that the form of ownership, organization and sector control is not a desirable end in itself, then the answers must be sought in the alternatives that are likely to be most effective in achieving the fundamental objectives: provision of adequate power supply at reasonable prices and with minimal wastage of resources. Interestingly, such a subordination of means to the desired ends is also reflected in a recent quote attributed to Chairman Deng Xiaoping of China: "it doesn't matter if a cat is black or white, as long as it catches mice." 54/ As a practical matter therefore, the choice of public versus private power -- or mixed ownership -- depends upon which will be the most effective in a given context. In this regard, the U.S. experience suggests that on balance, private ownership and operation (under the right market and regulatory environment) is an economically more attractive alternative to public ownership. Therefore, to the extent that publicly owned and controlled power systems in developing nations are subject to similar deleterious forces and conditions as those in the USA -- e.g., availability of low cost financing, heavily subsidized public power rates, inefficient tariff structures, lack of financial discipline, excessive government interference, etc. -- this would suggest a recommendation in favor of increasing private participation in the power sectors of such countries. In contrast, if a public power agency is required to meet all operating and investment costs from revenues (e.g., EdF in France -- see Annex 2), then the extent of efficiency losses would be limited to any managerial inefficiencies that may be present [53] as well as losses from delayed innovation. However, even in such instances, the public power agency should be answerable, - 54- preferrably to the marketplace, to ensure that it has embraced least cost planning, efficiency pricing, and properly accounted for any externalities. A key point that needs to be reinforced is that a more fundamental issue than ownership type is the extent to which the market organization and any regulatory control instills the rigors of a competitive market type discipline on its participants. Thus, even if some elements of the market are under public ownership, it is extremely important that they also be subject to such discipline. For ultimately, performance boils down to managerial attitudes and incentives. The U.S. experience suggests that the injection of cormpetitive elements -- actual or threatened -- are likely to do more for helping acheive higher standards of performance than regulation, or other control and oversight interventions. This is not to suggest that regulation can be entirely eliminated. Indeed, some aspects of the power market such as distribution are intrinsically monopolistic and would have to be regulated to some extent. Even in such instances, however, competitive pressures can be applied, for example, by franchise bidding with renewal based upon a review of performance. More specifically, the following options offer significant potential for efficiency gains in the power sector. - Bidding by private sector for new generation capacity - Franchise competition - Privatization - Foreign enclave operation (generation only) Those developing countries which are plagued by chronic power shortages and where the private sector has the necessary expertise and access to capital, could benefit by permitting private companies to build, own, and operate power plants. If a national or even regional grid already exists, then interconnected operations with multiple suppliers - some public and some private -- would create a competitive bulk power market with the lowest cost suppliers commanding an edge and providing a comparative yardstick for others to match. This for example is the situation in Pakistan, where WAPDA the state owned utility is facing a substantial and growing generation deficit (presently, over 30 percent of firm capacity). WAPDA has therefore invited both local and foreign investors to participate in thermal power plant construction and - 55 - coal mining development schemes (Lakhra project). Meanwhile, KESC - a private company serving the Karachi area -- is divesting itself of its generation responsibilities (to WAPDA), and taking over more distribution functions. The KESC example introduces the possibility that spinring-off, decentralization, or franchise competition might be desirable in the context of a distribution monopoly. Specific provisions would be stipulated as regards service conditions, and performance indicators would be reviewed periodically (e.g., 5 years), with competitive entry potential to permitted new entrants say, every 15 years. One example along these lines is the case o7 LECO in Sri Lanka, newly created under the private companies act (although government owned), to take over run-down distribution facilities now owned and operated by local municipalities. LECO is run like a private autonomous utility and purchases bulk power from the state utility, CEB. In many developing countries the government owns major hydro projects. Privatization in this context would involve selling rights to the falling water or the power output at the busbar to a privately owned company. Additionally, privatization could involve selling one or more publicly owned thermal plants, or simply subcontracting the operation of such plant for a given period, with specific performance standards and incentives. Foreign enclave operations would involve outside parties building and operating a power plant that feeds into the main grid. Most notably, in recent years the Chinese government has allowed the construction and operation of such a plant. Two other options are potentially very important in the context of developing countries: 1. Incentives for decentralized (independent) power generation such as cogeneration, dedicated generation for sale, etc. 2. Better use of existing captive or private generation. These initiatives have the advantage that they do not involve a substantial restructuring of the power sector, but can have a significant impact in augmenting available capacity, even in the near term. In particular, cogeneration shows promise (especially in many middle income developing countries) as a means of enhancing energy conservation in industry as well as improving overall efficiency of power generation. A recent study estimates that in many countries such systems can provide over 10 percent of the generation capacity with modest additional capital expenditures. - 56 - It is further estimated that cogeneration could provide between 6 and 10 gigawatts of electric power in the commercial and industrial sector of the subset of countries that were studied [2]. Before such potential can be realized the governments and power authorities concerned have to develop a clear policy regarding interconnection requirements, tariffs, reliability, wheeling, financing, accounting, institutional issues, regulatory aspects, etc. The U.S. experience with PURPA could provide a good starting point for studying the possibility of introducing PURPA-type legislation for the power sector in other countries. Developing countries are in a good position to benefit not only from the positive aspects of PURPA, but also avoid potential pitfalls. Some recent difficulties that could lead to inefficiency, identified in the U.S., include: 1. Pressure on utilities to purchase from private generators at prices that exceed their full avoided costs, including cases where the utility is obliged to pay capacity costs to the private supplier, while itself having excess capacity. 2. Utilities being obliged to offer incentive payments to encourage private generators (in excess of avoided costs), or having to deviate from optimal load despatch or system operation because of such purchases. 3. Restrictions on the utilities ability to solicit bids for private capacity, on a competitive basis. Finally, policy initiatives should attempt to encourage the release of existing captive generation capacity. In many developing countries a substantial amount of the toal national installed generating capacity is dispersed across a number of large industries, e.g., public and private textile mills, sugar factories, etc. The presence of such capacity is often driven by a lack of faith in the reliability of grid supplies [39]. Regardless of the motive, this capacity -- or a portion thereof -- could provide significant efficiency gains, at the very least from a system reliability perspective. Tapping this promising potential will require addressing the same set of issues discussed in the preceding paragraphs. - 57 - NOTES 1/ Alaska Power Administration (APA), Bonneville Power Administration (BPA), Southeastern Power Administration (SPA), Southwest Power Administration, (SWPA), and Western Power Administration (WAPA) 2/ Exhibit 3-2 indicates that nearly 75 percent of nydro generation is under public ownership. 3/ Even with non-holding company pools, indirect incentives do exist for individual companies to independently move towards a least cost mix: pressure to keep their retail rates low, as well as the fact that under a centralized mode of dispatch, phantom calculations are performed after the fact to assess how the pool level fuel costs and savings from economy sales are to be allocated to the participants. / Indeed a reflection of such potentially decisive forces is the fact that no new power pools have formed for over a decade. Additionally, it has been reported that several of the existing pools have been experiencing internal division and controversy, and some might even break up [32]. 5/ Whereas in principle FERC will accept rates based upon marginal cost, in practice all the tariffs that they have accepted so far are average embedded cost based. 6/ These scenarios are discussed in a later section. 7/ For example, some forms of incentive regulation attempt to link the allowed return to a utility, with one or more performance indicators. The problem with such a piecemeal approach is that it can trigger certain forms of substitution behavior so that the system looks good along the selected performance dimensions, but has been compromised along other performance dimensions not being monitored or that are hard to monitor because, for example, they are of a long term nature. For example, if incentives are based upon generating unit availability rates, this could result in compromising maintenance schedules in the short-run. Similarly, the penalizing of over capacity, even when such capacity was "prudently" built, is likely to influence a capacity mix in favor of combustion turbines, in the near term. 8/ TVA has also been cited as the largest violator of the Clean Air Act 9/ The Watts Bar coal plant of TVA cost $61 1/kW. Comparable costs in 1982 dollars of some hydro projects were in excess of $3,000 per kW. - 58 - 10/ Chemicals, paper and pulp, food processing, petroleum refining, primary metals. 11/ Public Law P.L. 95-617, 95th Congress, 1978. 12/ Docket No. RM 79-55, Order No. 69, February 25, 1980. 13/ Under PURPA rules, a OF must meet certain ownership criteria, efficiency and operating standards, interconnection requirements, environmental criteria, and fuel use limitations. Annex 3 provides more details about some of these criteria. 14/ Further details about these exemptions are contained in Annex 3. 15/ American Electric Power Service Corp., Consolidated Edison, et al. versus FERC and American Paper Institute vs American Electric Power Service Corp., et al. 16/ As another example, it has been reported recently that the Puerto Rico Electricity Authority (PREPA) "has been particularly obstreperous and does not want anything to do with QFs," Cogeneration Report, April 25, 1986. 17/ As noted previously, the Supreme Court decision was announced in May 1983. 18/ Utilities, industry organizations (such as GRI, the Gas Research Institute) and manufacturers. 19/ e.g., Annual Report of the Gas Research Institute (GRI), Chicago, III., 1985 and other GRI reports. Some off-the-shelf systems are available now and others are expected to be available by 1987. A recent GRI study puts the commercial sector (hospitals, schools, restaurants, and hotels) technical potential as 175,000 MW, and an economic potential of 70,000 MW at $1,000/kW (EUW, September 30, 1985). 20/ Not included in this estimate is the potential from municipal waste to energy QFs. By the year 2000, it is estimated that 40 percent of all garbage will be processed through such plants. Up to 18 percent of U.S. waste will be processed in such plants within the next 3 years (Cogeneration Report, April 11, 1986). 21/ California (7,300), Texas (4,300), Louisiana (3,700), Pennsylvania (3,000), New Jersey (1,900), Illinois (1,800), Ohio (1,500), Florida (1,400), Miami (1,300), North Carolina (1,200). 22/ e.g., William W. Berry, Chairman of Virginia Power Co. is quoted as saying that the company wants to "postpone any commitment to major new construction" as long as possible. (Wall Street Journal, February 26, 1986). 23/ The recent dip in oil prices might slow down some of this activity in the near- term, e.g., see "140-MW Louisiana Cogeneration Project Postponed Due to Falling Gas Prices," EUW, March 3, 1986. However, for a different view see "Despite Slumping Energy Markets, Small-Power Growth Continues, Study Finds," EUW, May 12, 1986. 24/ Cogeneration and Small Power Monthly, December 1982. 25/ Avoided Costs Under PURPA: Expectations and Realities," Paula Rosput, Director Rates, PG&E, IEEE Winter Meeting, New York, February 1986. 26/ Cogeneration Report, March 14, 1986; EUW, March 24, 1986. 27/ "Annual Utility Bid Solicitations for Small Power Proposed By Mass.DPU," EUW, February 24, 1986. 28/ More recently the city of San Antonio, Texas, invited proposals from power suppliers (utilities, QFs, independent producers) to supply the city with 1,000 MW of power. They intend to compare any bids received with the cost of building such capacity themselves. (Cogeneration Report, February 14, 1986.) Also see, "TNP Asks for Cogeneration Offers As Possible Alternative to Lignite Plants," EUW, March 24, 1986. 29/ "PG&E Offers Non-Rate Base Recovery Bid for Diabolo Canyon: Value Based Pricing," EUW, November 25, 1985. For other examples of moves to utility plant and QFs on the same basis see: "N.J. Policy: Oust Plant From Rate Base If Cogeneration Is Cheaper and Cleaner," EUW, December 23, 1985; "Mass. DPU Sets Generic Hearings On Rate Treatment of New Utility Plant," EUW, February 17,1986. 30/ e.g., "Campbell Soup Wants Cogenerated Power Wheeled to Other Company Sites," EUW, December 23,1985. 31/ e.g., A test case is brewing in Hawaii, where PRI Energy Systems proposes to sell power excess cogenerated power directly to retail customers at roughly half the normal retail rate of Hawaiian Electric Co. FERC has certified the QF and the Governor was reported to be favorably disposed. (EUW, February 27, 1984.) 32/ Cogeneration Report, February 28, 1986. 33/ e.g., see results of EEI survey reported in EUW, February 10, 1986, p. 10. 34/ "Utility Survey Reveals What Customers Are Willing-to-Pay for Reliability," EUW, March 24, 1986. Indeed inadequate grid reliability has been reported as a key factor in at least two decisions to move towards cogeneration, including the case of an IBM facility in San Jose. In Texas, an Exxon refinery is considering more cogeneration following a major outage, in spite of the fact that the refinery is presently served by two 138 kV lines that ensure a high level of service reliability (EUW, January 27, 1986). - 60 - 35/ e.g., "Pacific P&L Snares 150-MW Exxon Land in Border Competition with Utah P&L," EUW, October 29, 1984. 36/ e.g., "Vermont Town Moves to Buy Out of Coop, Link Up with Citizens Utilities," EUW, April 14, 1986. 37/ e.g., A cogeneration equipment manufacturer is installing 65-kW cogeneration systems at two different McDonald's restaurants under a shared savings contract. McDonald's restaurants will not pay any costs upfront for equipment or installation, but will surrender a percentage of their savings. Cogeneration Report, May 23,1986. 38/ A more accurate phrase would be "non-treatment." 39/ For example, a recent State Court ruling in Massachusetts notes that utility s;hareholders "must, just as must shareholders of a competitive private corporation, accept the risks of the Company's failure. Failure could be due to the negligence or incompetence or simply unfortunate decisions of the Company's directors, to the imprudence of its contractor, or to conditions entirely external, such as the oil shortages of the last decade" (EUW, May 12, 1986). 40/ However, innovative rate designs based upon unbundled service, e.g., interrutible pricing, demand subscription, spot pricing, offer an economically sound way to move in this direction. Several such experimental programs are in progress at present. Under such schemes the traditional interpretation of a utHity's "obligation-to-serve" as an absolute standard, is more broadly interpreted within an economic framework. In the wholesale market, there are developments and encouraging signs which indicate that independently owned generating companies are willing to enter this market if permitted such flexibility in pricing. This issue is discussed later. 41/ "Major Policy Initiatives," Executive Office of the President, OMB, Fiscal Year 1987, p. 23 and supporting Appendix p. l-J23. 42/ In the late 1950s and 1960s it is reported that BPA failed to even recover operating costs. 43/ e.g., "Federal Power Sales Make Environmental Sense," David C. Campbell, World Wildlife Federation, Wall Street Journal, March 4, 1986. 44/ Congressional Record, Senate, July 26, 1984, S9292-S9306. 45/ e.g., (1) EUA is reported to have bought Seabrook shares at 21 cents on the dollar (Wall Street Journal, March 11, 1986; (2) "Accord Reached On Sale of Seabrook -1 Shares: Calls for Market Based Rates," EUW, January 6, 1986; (3) Prepared Direct Testimony of John Landon before FERC, Docket No. EL _ - *..4 I -61 - 46/ Some have ventured as far as to suggest that even the distribution function should be deregulated. The notion that distribution exhibits traits of a natural monopoly have been challenged on several grounds. It is argued that the commonly referred to problem of waste and duplicative costs and inconvenience of digging up streets repeatedly, installing two sets of poles and lines, the asthestic aspects, etc. is a problem of externalities that should be handled not by granting monopoly rights but by setting a proper price on the use of these scarce resources. Already in many of our streets, it is argued, there are two sets of poles (telephone, electric) and three sets of wires (telephone, electric and cable) [45] [48]. 47/ FERC Order 436, promulgated last fall, encourages pipeline companies to open their systems to other pipelines and gas producers and distributors. Thus pipeline companies would become more like transportation companies moving gas between suppliers and users for a fee. "Gas Pipeline Industry May Be Facing Shakeout As More Companies Become Common Carriers," Wall Street Journal, April 16, 1986. Also see, FERC Wheeling Move Raises Consumer Carrier Scare for Private Utilities," EUW, July 2, 1984. 48/ These prices may be set to ensure capital recovery as well. 49/ For example, to assess the efficiency gains and losses, transaction costs, distributive effects, regulatory, social, legal (including anti-trust) aspects. 50/ Some potential examples include: (a) Inter-Power Corporation of New York proposes to build and operate a 200 MW plant near Waterford, NY, using fludized boilers fired by coal and pelletized municipal waste. Steam would be sold to a nearby General Electric Silicon Products Division plant, and power to Niagara Mohawk (Cogeneration Report, May 23, 1986). (b) Northeast Energy Associates, proposal to build and operate 250 MW gas fired combined cycle cogeneration plant. Electricity would be sold to Boston Edison and others. Steam will be sold to as yet unspecified customers. (Cogeneration Report, May 23, 1986). 51/ Some efforts in this direction are described in the following: "Colorado Bill Would Deregulate New Power Facilities Built for Wholesale," Electric Utilities Weekly (EUW), March 12, 1986; "BG&E Proposes Energy Sale Using Market- Based Rates and Competitive Risks," EUW, April 14, 1986; "FERC Accepts Citizens Energy Corp. Plan to Be First Wholesale Broker/Marketer," EUW, May 19, 1986. 52/ e.g., see "Pacific Northwest Utilities Eye Forming Competitive Bulk-Power Market," EUW, May 12, 1986; "NARUC to Look At Expanding Florida Brokerage Systems Throughout Southeast," EUW, March 26, 1984. -62- 53/ This recognition may partly underly the recent passage of a law in Nebraska which calls for total deregulation of phone rates in the State. Government approval is no longer necessary to increase phone bills even in areas where there is no competition. Explicit recognition was given by the Governor to the fact that regulation stifles innovation: "if government gets out of the way -- they'll come in here and show us what all their technology can do for our people." Court challenges are expected. Nevertheless, this development represents a major departure from the cost-of-service regulatory mind set. (Wall Street Journal, May 21, 1986; Washington Post, May 27, 1986.) 54/ This statement was made in the context of privatizing public housing: Huan Xiang "On Reform of the Chinese Economic Structure," Beijing-Review, November 13,1985, quoted in [63]. ANNEX 1: ORGANIZATIONAL HISTORY OF THE U.S. POWER INDUSTRY The discussion in Section 3-1 clearly reveals that the market structure and organization of the U.S. power sector is not monolithic; that a plurality of forms exists. This raises some natural questions: why does such multiplicity exist? How did it evolve? Have other structures been tried and discarded? What are the major lessons learned about such organizational alternatives? This section traces key developments in the U.S. power market since its inception in 1882, with a view to provide insights into these questions. 1882-1907: Industry Organizes The period 1882-1907 can be characterized as one of unbridled, privately owned and franchised competition. In the early part of this period, non- exclusive competitive franchises were freely granted in a haphazard manner to privately owned companies to sell electricity. This early phase was paralleled by a consolidation phase where the motivation for the electric company was to eliminate competition and raise rates. New franchises were granted to combat these effects. However, eventually most smaller companies were "devoured" by persistent and growing monopolies who had entered the competitive fray earlier. For example, whereas at one point Chicago had forty-seven franchises, by 1897 the Commonwealth Edison Company acquired twenty-three different franchises and substantially eliminated all - 65 - competition. Similar experience is documented in other cities such as New York, Detroit, Denver L28]. By the early 1900s it became apparent that reform was necessary to combat the mounting confusion, inefficiencies, and other "evils" that had become commonplace. There was no standardization of service frequency, voltage, type of equipmc.nt, equipment sizes. Fragmentation also resuited in missed opportunities from capturing the beneffts of load diversity, scale, etc. In addition, considerable graft and corruption prevailed in the granting and monitoring of franchises. Utilities were perceived as victims as well as agents that were instrumental, together with municipal officials, in creating this situation. 1907-1932: Three Distinct Models of Ownership and Control Emerge The failure of private competition and the various theories of regulation were debated and investigated vigorously. The issues were well understood. The major preferred altematives were private monopoly under coalition of civic reformers and many privately owned utilities eventually emerged, based on this model. It was agreed that under this model, private enterprise would result to the public advantage since the commission could fix rates and set service standards. If the community was dissatisfied it could buy the utility's plant at its depreciated value. This threatened competition, it was felt, would be sufficient to keep the companies in line. In 1907, Wisconsin and New York were the first states to establish Public Service Commissions (PSC). By around 1920, this model of private -66 - monopoly ownership and state regulation gained favor in 26 states. However, six states opted for public ownership. The latter reflected continuation of a sentiment among some segments that had become increasingly appealing during the period 1896-1906 when the number of publicly owned systems tripled in response to the prevailing dissatisfaction with existing inefficient private systems. Unfortunately, one beneficial aspect of the early competitive flurry was lost in the move to the regulated monopoly structure. In addition to rate competition between electric companies, there was substantial inter-fuel competition in end-uses, between gas, coal, fuel oil, and electricity. Thus, dffferential electricity rates were offered by end-use and even by customer class. This can be characterized as value-based pricing for unbundled service. This practice of product differentiation, market segmentation, and value-based pricing that is typical of competiive markets has been lost under the monopoly market structure that has prevailed since. In this regard, the situation seems to have come full circle again after 100 years. The reemergence of inter-fuel and end-use technological competition has created competitive market pressures for utilities to unbundle service by offering a choice of service options differentiated along the end-use and/or the reliability attribute as well as offer competitive rate discounts to large users who threaten to switch to natural gas, self-generate or move to cogeneration. These aspects are discussed in greater detail later. Whereas the two distinct monopoly models represented the dominant form of ownership and control, some competition continued to flourish among them. Duplicative competition between public and private utilities prevailed in many regions, e.g., Cleveland, Los Angeles, Illinois. Rates in those areas were generally among the lowest in the country. It is reported that this type of - 67 - competition received wide publicity and was a "thorn in the side" of the pro- monopoly forces, chiel among them being the state commissions themselves, most of whom by that ti me firmly believed competition to be wasteful and bad. Two further paral,el developments were significant in the period 1920-1935: Dissatisfaction with state regulation grew considerably by the 1920s and became a popular political issue culminating in reform in the form of federal regulation to combat &buses." Emergence of a National Power Policy, a component of which was the introduction of government competition in the power sector through the federal funding of publicly owned utilities" Over the period 1928-1935 the Federal Trade Commission (FTC), at the direction of the U.S. Congress, produced a ninety-six volume study that delved into, among other problem areas, the excesses of holding companies such as, company propaganda techniques and pyramiding. The FrC report laid the groundwork for the era of federal regulation by the Federal Power Commission (FPC), and the Securities and Utilities Holding Company Act (PUHCA) of 1935. Its "death sentence" clause called for eliminating 2 "the evils" of pyramiding and other abuses. This essentially limited each holding 3 company to a single-level, integrated operating system, among other things. The mid-1930s also marked the beginning of large scale development of public power (primarily hydro) projects in the form of the Tennessee Valley 4 Authority (TVA) Act of 1933 and the Bonneville Power Act. These reflected a central component of President F.D. Roosevelt's National Power Policy under which government competition by example or as a threatened alternative would - 68 - serve as the "birch rod in the cupboard" to privately owned utilities. He is quoted as saying that "if public regulation does not prove to be satisfactory, another and more radical remedy will certainly be tried." Roosevelt viewed government- induced competition as an alternative to state regulation. Not only did TVA bring about rate cuts of the order of 60 percent in its service area, but in addition its existence as a threatened alternative in regions adjoining the TVA territory had a dampening affect on private company rates there as well. It should be noted here in the case of the hydro power projects, there were other and often dominant motivations (such as employment creation during the economic slump) for developing the project, given their multi-purpose nature. Of course, the benefits of power were clearly recognized. However, if the Idea of govemment competition as an altemative to regulation had not existed it is unlikely that the govemment would have insisted on generating and distributing the power 6 itself. Rather, the government could have sold the rights to the falling water, to a private utility company which could then have enerated and distributed the power itself. This did not happen with one exception. Finally, the year 1935 also marked the beginning of the Rural Electrification Administration (REA). Federal monies were provided at low interest and easy terms for the purpose of extending electric service to rural (i.e., farm) areas without access to central station service. Rural cooperatives (COOPs) were formed by farmers to build power lines to link up with the nearest wholesale supplier. Loans were also provided to a group of COOPs to build their own generation facilities if private companies charged exorbitant rates. -69- The advent of such G&T COOPs introduced a signHifcant element of competition in the market. This competition took two forms: as a threatened alternative and as a real alternative. Under the non-competitive clause, REA loans were initially restricted to provide service to rural areas that were unserved. This in itself did not solve the problem. In many cases, COOPs were not within economic transmission distance of a federal or state hydro plant. In such instances, they had to rely on wholesale purchases from private utilities who were often unfriendly and sold at rates that were considered unreasonable. To combat this problem loans were provided to a group of COOPs to generate and transmit their own power. In many instances, the threat of this action was sufficient to force the wholesaling private utility to reduce rates or even to supply power in cases where it had been heretofore refused. In addition, often such benefits spilled over to neighboring COOPs in dealings with their wholesale supplier. The competitive pressures increased in later years when three-tier COOPs were created to capture further efficiencies from horizontal integration. Such "super COOPs" are federations of two-tier G&T COOPs formed for the purpose of building and operating large baseload steam power plants and high voltage transmission lines to interconnect their steam generation and loads with federal or state hydroelectric projects. By the 1960s most G&T COOPs were integrated into regional power grids and pooling arrangements. Any institutional or market barriers to such integration were removed by virtue of enhanced regulatory powers provided to FERC which: - compel lOUs to sell wholesale power to COOPs and MUNYs, - 70 - give FERC the power to set wholesale rates that are just and reasonable, and require non-discriminatory admission of such systems Into regional company grids. The subsidized low interest loans coupled with a tax-free status have resulted in relatively lower power rates for COOP customers. Many of the larger G&T cooperatives have therefore found it lucrative to expand since the 1960s into urban areas and serve some industrial load as well. Indeed, statistics indicate that in the last two decades over 80 pereent of the new COOP customers were non- farm accounts. - 71 - ANNEX 2: POWER SECTOR STRUCTURE IN SELECTED FOREIGN COUNTRIES This section provides a brief description of the ownership and institutional structure of the power sectors in England, France, West Germany, Japan, and Sweden. Two constraining factors have greatly limited the scope and level of detail offered in the following discussion: resource availability coupled with a paucity of publicly available information in the U.S. Nevertheless, based upon a review of this limited literature ([10], [18], [29], [56]) it appears that efforts to further investigate and understand the organizational and market structure of the power sector in some of these nations (e.g., Sweden, West Germany, France) could provide valuable insights in developing restructuring alternatives for the developing countries. Exhibit A2-1 presents data on installed generation, production and consumption in fifteen of the largest countries worldwide. The figures therein help provide a starting contextual perspective of the relative sizes of power markets in those counltries. Exhibit A2-2 provides a summary overview of the ownership and regulatory structure in several countries. - 72 - EXHIBIT A2-1 THE FIFTEEN LARGEST POWER MARKETS WORLDWIDE Source: EEl, Statistical Yearbook, 1984. 1963 _ _ CawWv ",a'e Ne N*e t tThWn Total M4va NUCI tlltII TOW (Thaumm) Caq.t un'td Sam 796. 67.073 52&.96 6741937 333A.5 20&77 1.740.395 2.366 23.0233 10.117 U.S .a. 6.968 20.W0 216.573 263.55 160.362 66.000 1.142.72 1.40100 272.50 5.167 Jaow 34.35 17.6t7 107.181 110.300 87.0 M06=76 406869 608357 119.206 S.C53 CaoW 51.000 0.100 29.700 09.0W0 26.024 4.0 0330 4I443 24.66 16.415 Gwmy(IW6W3 6.531 1109oN 66137 86.51 16.03 663 23.07 373.813 61.43 6.079 Chu (mafaIw) 29.000 - 55.000 6.o000 6I360- - 265.060 25M 1.022.054 344 Ptp.nc 21t200 26.60 30.200 76200 70.600 137.000 ?A560 263.00 54.62 3.166 Umes Kigdoen 2.721 6.460 67.220 6.6431 6.466 0.926 210A.61 276L227 56.00 A.932 imy 17.125 1,273 33.100 51.46 44.216 5.793 132.,91 I62.660 66.633 3.218 Indi' 14.003 60 27.317 42.160 51.566 2.166 64.228 147.1 20j.572 203 razi 34.035 - 6.062 40.7 151.471 - 10.49 161.570 131306 234 soon 13.180 1.906 16.480 31 650 2r27.6 9.000 re7.66 115.450 38.234 3.020 s-Osh s1.297 7,355 6.068 30.710 64.349 40.903 4.264 1096.3 6.331 13 '60 AuCVM 6.340 - 23.872 30.212 12.913 - 93374 106L307 15.M5 6.063 =--7ant t1977 - 24.61 26.833 3.321 - 122.500 125.61 . 36.56 3i41 _ _ _ _ _ - .~~~~~~~~~~~~ - 73 - EXHIBIT A2-2 COMPARISON OF OWNERSHIP AND REGULATORY STRUCTURE IN SELECTED COUNTRIES Private Rate Country Ownership Regulation Other Ownership Australia - - State ownership and rate setting Austria X X Belgium X X Denmark X X Joint governmentlutiity ventures Finland - - National and municipal ownership France - - National ownership Germany X - Government utilities also exist Greece - - National ownership Hong Kong X X Ireland - - National Ownership; other reg. authorities Italy - - As above (Ireland) . Japan X X Joint government/utility ventures Korea - - Nationalization underway Kuwait - - National ownership; complete subsidy Netherlands X X Joint government/utiity ventures New Zealand - - National generation, local distribution -74- Norway - Private and municipal gener., national transmission Portugal - National ownership Saudi Arabia - Nationalization underway Singapore - National ownership South Africa - National ownership Spain X X Utility consortium coal-buying Sweden (Review) Public and private generation and distribution Switzerland X Taiwan - National ownership Turkey - National ownership UK - National ownership Source: [18] -75 - A2.1 ENGLAND Nearly 95 percent of all generating capacity and all bulk power transmission is owned and operated by a national agency, the Central Electricity Generating Board (CEGB). The rest consists of industrial generation. The CEGB markets its power wholesale to over a dozen local Area Electric Bopards that have responsibility for distributing it to consumers within these respective monopoly franchise areas. Electric power policy - pricing, planning, generation mix etc. - is the responsibility of the Electricity Council (which has representation from CEGB and the Area boards). In these matters the Electricity Council is provided policy guidelines by the Cabinet. Bulk power tariffs of the CEGB are based upon marginal costs. It is unclear as to what performance standards are expected of the CEGB and the Area Boards in terms of adequacy, efficiency, financial performance etc. Nor is it apparent as to the degree of autonomy provided and the underlying incentives faced by management in the operating organizations. A2.2 FRANCE The bulk power market in France is dominated by the public owned corporation Electricite de France (EDF). About 15 percent of this market is - 76 - supplied by industrial generation, municipal generators and other state entities. However, govemment rules preclude this market from functioning in a competitive fashion. The retail power market is totally dominated by EDF in that it owns virtually all of the distribution lines, with the exception of a few MUNYs and COOPs. EDF's tariffs are marginal cost based. Whereas it is a public corporation, EDF is required to meet certain financial performance standards in addition to meeting all operating and investment costs from revenues. A2.3 WEST-GERMANY The West German power market is dominated by mixed -- public and private - ownership. Nearly 70 percent of the bulk power market sales are provided by about 100 such jointly owned enterprises with most of the remainder provided by purely publicly owned generation and a very small amount provided by generation that is owned entirely by privete investors. Public investment - federal, state, MUNYs, t-UDs, etc. -- accounts for about 70 percent of totat investment in guneration. Whereas ownership of generation is highly decentralized, the bulk power market itseff is dominated by nine vertically integrated and interconnected systems that together account for over 80 percent of all power sales. These systems jointly own and operate the bulk power transmission grnd. -77 - Retail distribution of power is carried out primarily by MUNYs or rural COOPs. Power Is supplied through purchases from the wholesale market, supplied by their own units in some instances, and also purchased trom generators owned by industry. Wholesale rates are directly regulated by the federal govemment. Retail rates and transmission charges for large users and industrial generators are negotiated directly between the parties involved. An element of competition exists in that if such users cannot succeed in negoting a satisfactory rate they are then permftted to negotiate service from a more distant utlity. A2.4 JAPAN The Japanese power sector bears striking similarities in its ownership and organizational structure to the U.S. Nine fully vertically integrated and privately owned power companies operating under exclusive monopoly franchise rights in their respective areas together account for about 80 percent of all sales. The remainder Is supplied by a handful of small utilities and by Industrial generation. In addition, two other organizations operate in the wholesale power market by selling output to one or more of the lOUs. The Japan Atomic Power Company (JAPCO) operates several nuclear plants that are jointly owned by IOUs. Finally, another company -- mostly owned by the government and in small part by the IOUs -- has developed and operates large hydro projects. This power is then marketed wholesale to the IOUs. - 78 - Regulatory oversight and control in the matter of rates and as regards industry performance is in the hands of the Ministry of International Trade and Industry. A2.5 SWEDEN The Swedish power sector comprises four primary ownership dasses: state owned (Vattenfall), MUNYs, private power corporations, and industrial power producers (mostly cogeneration). Statens Vattenfallsverk (VF) through direct ownership and joint partnership with private power corporations controls almost 75 percent of the nation's nuclear capacity and most of the major hydro facilities. VF produces almost half the national energy needs, mostly from its hydro facilities. Most generation facilities in the country are linked to the national grid, a substantial portion of which is owned by VF. Participation requires that members meet strict requirements as regards operating reserves, reliability etc. Further, members have access to the grid based upon reserving capacity on the grid on a long term lease basis. Penalties are imposed for exceeding these levels. Underutilized but reserved capacity can be sold and purchased between members on a spot price basis. The bulk power market operates as a competitive and efficient exchange market based upon the system lambda type of economy exchange transaction that occur in many parts of the U.S. -79- Competitive elements prevail in the Swedish power system in the retail markets. For example, N a firm is dissatisfied with the local utility rates, it is free to negotiate more favorable purchases elsewhere and have them wheeled. Invariably, this threatened competition has the desired effect in that the local utility adjusts its prices accordingly. -80 - ANNEX 3: SUPPORTING INFORMATION ON PURPA A3.1. Qualifying-Facliity-(QF) To be admitted to qualifying facility status, a small power producer or 9 cogenerator (either its owner or its operator) must meet the following conditions: Cogeneration is defined as the "sequential production" of "electric energy and steam or forms of useful energy (such as heat) which are used for industrial, commercial, hearing, or cooling purposes." The energy can be used in either order. Satisfy any rules prescribed by FERC such as minimum size, fuel use, fuel efficiency, reliability, etc. Is owned and operated by a person not primarily engaged in the generation or sale of electric power (other than power from cogeneration and small power production). The operating and efficiency eftindards and ownership criteria for cogeneration to obtain qualifying facility (OF) status are summarized on Exhibit A3-1. - 81 - EXHIBIT A3-1 COGENERATION FACILITY STANDARDS FOR QUAUFICATION UNDER PURPA TOPPING CYCLE BO0TOMING CYCLE Operating 5% of total energy none Standard output must be useful thermal energy Efficiency If thermal output is Useful power output Standard 15%, power output must be at least plus half of thermal 45% of annual oil and output must be at gas used for supple- least 45% of annual mentary firing. oil and gas input. If thermal output is 15%, power output plus half of thermal output must be at least 45% of annual oil gas input, Ownership Utilities may not own more than 50% of a Qualifying cogenerator -82 - A3.2 Environmental-Criteria FERC has concluded that cogeneration will produce a net environmental benefit nationwide, since less total fuel will be burned in the combined generation of electrical and thermal energy. Nevertheless, cogenerators must meet the requirements of the Clean Air Act in order to obtain the necessary environmental permits to operate. Three levels of emission standards u Jst be met: 1. - National Ambient Air Quality Standards (NAAQS) for each facility's air quality control cannot be exceeded. 2. - In attainment areas where air quality standards have been met, prevention of significant deterioration (PSD) increments cannot be exc'-ded, and best available control technology (BACT) must be used for emission controls. - In "non-attainment" areas, i.e., areas where air quality standards have not been achieved, emission controls that result in the lowest achievable emission rate (LAERR) must be used for the non- attainment pollutants, and new emissions of these pollutants must be offset by reductions in emissions from other sources. For example, ff air o"iality standards have not been achieved, in a certain county, all but small cogeneration installations are likely to require a PSD permit prior to construction. This could require "shopping around" to find someone willing to sell such rights. 3. Power Stack emissions must meet the Environmental Protection Agency's (EPA) New Source Performance Standards (NSPS). - 83 - A3.3. Special Exemptions to QFs - All cogenerators are exempt from the Federal Power Act and from the Public Utilities Holding Company Act, with some minor excepticns (biomass- powered small power production facilities under 30 MW) - All small power production facilities (but not cogenerators) between 30 and 80 megawatts are still subject to the Public Utility Holding Company Act, Federal Power Act, and state regulations. - All blomass facilities are subject to the Federal Power Act but exempted from the Public Utility Holding Company Act and state regulations. A3.4. Fuel Use Limitations for QFs The Power plant and Industrial Fuel Use Act of 1978 (FUA) is aimed at significantly reducing the use of oil and gas and the encouragement of use of coal and altemate energies. Wifth certain exceptions that can be granted by DOE to utilities and industrial facilities, the Act prohibits the use of oil or gas as a primary fuel in newly constructed generating facilities which have a fuel input rate of 100 10 million BTU's per hour or greater. The Act provides for specific exemptions for cogenerators. A non- boiler major fuel buming installation (MFBI) that cogenerates (an MFBI cannot sell more than 50 percent of the power it produces) is permanently exempted from the regulation. An Industrial cogenerator with an oil or gas fired boiler can be exempted if it can be demonstrated that (1) the facility will save oil or gas; (2) the use of coal mixed into the fuel would be technically or economically infeasible; and -84 - (3) the facility has satisfied an environmental impact analysis. While this last condition scares many potential investors, it often does not require any more than the information needed to obtain environmental permits for the facility. The Act also provides exemption for cogeneration facilities as long as the "economic and other benefits of cogeneration can only be obtained through the use of oil or gas." Finally, under the FUA, a QF is defined more strictly than under PURPA - of the total energy output of the plant, at least 10 percent must be thermal energy output and at least 5 percent electrical output. - 85 - ANNEX NOTES 1. Exceptions Include the duplicative public vs. private competition in Seatte, Tacoma, and In later years in Cleveland. Indeed, Cleveland represents the largest of approximately 50 cities in the U.S. that are served by public and power companies in head-to-head competition even today. In Cleveland, there are many streets with two different sets of wires running down each street [36]. 2. It was acknowledged however that holding companies did offer some of the rate benefits associated with economies of scale and exchange efficiencies. 3. The record suggests a compromise that privately owned companies obtained was the elimination of provisions in the Act .o convert their grids to "common carrier" status. 4. Loans and grants for some projects were channeled through the Public Works Administration (PWA) that was set up In 1933 at the height of the depression, in order to stimulate the economy. 5. A phenome;"mn also observed in several other cities such as Cleveland, Seattle, etc. where public versus private competition prevailed. 6. In many cases government transmission lines were erected to bring power to tife publicly owned systems within economic transmission distance. 7. Generation facilities on the Hoover Dam have been leased to a private company and a municipality. The lesees generate, transmit, and distribute the power [47]. 8. The Colton decision of the U.S. Supreme Court (1964) confirmed FERC's jurisdiction over wholesale power transactions and in essence upheld FERC's single-network doctrine that the flow of electricity in any integrated interstate network represented inter-state commerce and hence fell under its jurisdiction. 9. Small power production is defined as production of electricity primarily from biomass, waste, renewables (wind, solar), storage, hydro or any combination thereof. In addition, the total power production capacity at the rate of such a facility plus any other facility should not exceed 80 MW. 10. Presuming that the cogeneration plant converts somewhere between 40 percent to 75 percent of its fuel input energy to electricity, this implies that cogeneration plants with capacity larger than 12 to 22 megawatts would come under the provisions of the FUA. - 86 - SELECTED BIBLIOGRAPHY 1. Acton, Tom P., Besen, Stanley, M., "Regulation, Efficiency, and Competition in the Exchange of Electricty, First-Year Results from the FERC Bulk Power Market Experiment," Rand Corporation, R-3301-DOE, October 1985. 2. Agency for Intemational Development (US AID), "Cogeneration in Developing Countries: Prospects and Problems," final report prepared by Hagler, Bailly and Company, Washington, DC, 1986. 3. American Public Power Association (APPA), "The Public Benefits of Public Power," May 1984. 4. Anderson, Douglas D., "State Regulation of Electric Utilities," in James Q. Wilson, ed., The Politics of Regulation, New York: Basic Books, 1980. 5. 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Schulz, Walter, "Conditions for Effective Franchise Bidding in the West German Electricity Sector," in Mitchell, Bridger, Kleindorfer, Paul, ed. "Regulated Industries and Public Enterprise," Lexington Books, Lexington, MA, 1979. 57. Smith, Jeffrey C., "Testimony Before the House Committee on Interior and Insular Affairs, Water and Power Resources Subcommittee, Director, Privatization Alliance, Citizens for a Sound Economy, Washington, D.C., February 20, 1986. 58. Spann, Robert M., "Public versus Private Provision of Governmental Services," in Thomas Borcherding, ed., Budgets and Bureaucrats, Durham, N.C.: Duke Unversity Press, 1977. 59. Stanbury, W.T., Thompson, Fred, "Regulatory Reform in Canada," Institute for Research on Public Policy, Montreal, Canada, 1982. 60. Stigler, George, Friedland, Claire, "What Can Regulators Regulate? The Case of Electricity," Journal of Law and Economics, Vol. 5, 1962. 61. Tennessee Valley Authority (VA), "A History of the Tennessee Valley Authority," IVA report, 50th Anniversary Edition. 62. Varley, Andrew, "Is the Electric Utility Industry Ready for Deregulation?," Public Utilities Fortrightly, September 19, 1985, pp. 17-20. 63. Young, Peter, "Privatization Around the Globe: Lessons for the Reagan Administration," Adam Smith Institute, National Center for Policy Analysis (NCPA), Report #120, Dallas, Texas, January 1986. 64. Wilson, James Q., Rachal, Patricia, "Can the Government Regulate Itself?," The Public Interest, Winter 1977. 65. Wilson, James O., Richardson, Louise, "Public Ownership vs. Energy Conservation: A Paradox of Utility Regulation," Regulation, September/October 1985, pp. 13-38. ENERGY SERIES PAPERS No. 1 Energy Issues in the Developing World, February 1988. No. 2 Review of World Bank Lending for Electric Power, March 1988. No. 3 Some Considerations in Collecting Data on Household Energy Consumption, March 1988. No. 4 Improving Power System Efficiency in the Developing Countries through Performance Contracting, May 1988. No. 5 Impact of Lower Oil Prices on Renewable Energy Technologies, May 1988. No. 6 A Comparison of Lamps for Domestic Lighting in Developing Countries, June 1988. No. 7 Recent World Bank Activities in Energy (Revised September 1988). No. 8 A Visual Overview of the World Oil Markets, July 1988. No. 9 Current International Gas Trades and Prices, November 1988. No. 10 Promoting Investment for Natural Gas Exploration and Production in Developing Countries, January 1989. No. 11 Technology Survey on Electric Power Systems, February 1989.