ATTACHMENT 3 ATTACHMENT 3 PROCEDURAL HISTORY AND POSITIONS OF THE PARTIES I. Procedural History Faced with average electric rates approaching 150 percent of the national average, in April 1992 we directed our Division of Strategic Planning to prepare a report that (1) described current conditions and future trends facing the electric industry, and (2) examined alternative regulatory approaches in light of those conditions and trends.1 This report, entitled California's Electric Services Industry: Perspectives on the Past, Strategies for the Future was issued on February 3, 1993. Referred to as "the yellow book" because of the color of its cover, this report presented a history of the electric industry and California's regulatory structure from 1945 through 1993. The yellow book concluded that current regulatory approaches were incompatible with emerging trends in the electric services industry, and presented four broad strategies for regulatory reform. In concluding that the state should reform its regulatory program governing the electric industry, the report stated. The fundamental tenets of California's contemporary regulatory compact emerged when the monopoly character of the electric utility industry was strong and secure. Today, competitive pressures and emerging market forces exert increasing influence over the structure of the industry, and the utility's monopoly position is less intact. Consequently, the Commission should take appropriate reforms in order to establish greater compatibility between regulation and the industry that regulation guides.... Mounting competition among energy service providers and increased pressure to allow consumers to benefit from competition through greater choice will shape the future structure of the industry. As such, reform is required in order to ensure that California is well positioned to benefit from a competitive future. (Yellow Book, p. 140.) To begin the discussion of reform, the yellow book offered four broad strategies. These ranged from a limited reform strategy, which would principally maintain the current cost-of- service regulatory model with some modifications, to a strategy 1 Decision (D.) 92-09-088 mimeo., p. 17. A3.1 ATTACHMENT 3 ATTACHMENT 3 that would promote a competitive market for electric services through mandatory divestiture of generation by the state's three major electric investor-owned utilities. The release of the Division's report followed closely on the heels of the passage of the Energy Policy Act of 1992 (EPAct)2 EPAct encourages states to foster competition and a greater reliance on market mechanisms as the preferred means to develop and deliver energy services. In order to achieve the vision articulated in EPAct, Congress significantly reformed certain federal laws, some of which were originally enacted as far back as the 1930s. For the most part, however, Congress refrained from imposing a single, prescriptive approach on the nation. Appropriately, Congress chose instead to grant states and regions broad latitude to develop the specific policies and programs required to make EPAct's vision a reality. In response, we initiated a broad public dialogue on the electric services industry. The first step in this dialogue was to solicit comment on the yellow book findings and strategies for reform. We sat together in three full panel hearings to hear the views of a wide range of industry stakeholders, consumers and experts on industry trends, the role of utilities in alternative industry structures, and the need for regulatory reform. Fifty-seven individuals and organizations participated in this dialogue by filing written comments or presenting oral testimony at the three full panel hearings. On April 20, 1994, based on the yellow book, the full panel hearings and the written comments, we continued this dialogue by issuing an Order Instituting Rulemaking and Order Instituting Investigation (Rulemaking) on proposed policies for regulatory reform and restructuring California's electric services industry.3 Referred to as the "blue book" because of the color of its cover, the Rulemaking proposed regulatory reform and restructuring that would substantially reorient the way in which electric services are developed, delivered, and consumed in California. The primary goal of the Rulemaking was to explore methods to lower the cost of electric service to California's residential and business customers without sacrificing the utility's financial integrity. (Rulemaking, p. 1.) The Rulemaking proposed a two-track strategy for reform and restructuring. The first track would replace traditional, cost-of-service regulation with performance-based regulation, or PBR, and would tie a utility's profits to how well it provides low-cost, high quality services rather than to the utility's level of capital 2 Public Law 102-486, 106 Stat. 2776 (1992). 3 R.94-04-031 and I.94-04-032. A3.2 ATTACHMENT 3 ATTACHMENT 3 expenditures. Under the Rulemaking proposal, the Commission would rely on PBR in the sectors of the industry in which competition either does not exist or is impractical. (Rulemaking, pp. 35-37.) The proposed second track would gradually grant all of California's consumers of electric services voluntary and direct access to the market for electric generation services. This track would replace regulation with competition in those sectors in which competition exists and/or is feasible. As proposed in the Rulemaking, beginning January 1, 1996, large industial consumers could voluntarily choose to look beyond the monopoly utility and seek competitive services from other service providers. The number of consumers eligible to choose service providers through direct access would increase in a phased manner after 1996 until January 1, 2002, when all consumers would be eligible. No consumer would be forced to rely on choice through direct access to obtain services. Only those who voluntarily elect to do so would procure generation services directly from the competitive market. Under the Rulemaking proposal, consumers may remain with the regulated utility and continue to receive bundled electric services. In the Rulemaking, we recognized that the Commission's constitutional and statutory responsibility to ensure reasonably priced, safe, reliable, and environmentally sensitive electric service for California's consumers of electric services would endure under any reform initiative. (Rulemaking, pp. 14, 33-34.) In addition to securing these fundamental goals, the Rulemaking articulated several other goals to accomplish as part of the restructuring effort. These include decreasing reliance on litigation as the dominant decisionmaking tool; increasing reliance on markets and market-based regulatory solutions; reducing the costs and burdens that the public faces under the current regulatory framework in California; shifting the focus of California's regulatory apparatus and the industry toward the state's consumers of electric services; and moving competition from the administrative forum to the marketplace. (Rulemaking, pp. 7-8.) The Rulemaking also articulated several key principles intended to guide the industry during and after the transition to a more competitive electric services market in California. These principles include ensuring that the utility's financial integrity is not unfairly compromised. One of the key components in this regard was the proposed "competition transition charge," which would act to compensate the utility for any uneconomic assets resulting from the transition to increased competition under the Rulemaking's reform initiative. (Rulemaking, pp. 1, 44-47.) Another guiding principle embedded in the Rulemaking was the prevention of cost-shifting from one consumer group to another, or within consumer groups. (Rulemaking, pp. 10, 28.) A3.3 ATTACHMENT 3 ATTACHMENT 3 Finally, recognizing that increased consumer choice, greater reliance on competition and industry restructuring affect all sectors of the industry, the Rulemaking requested comments on proposals for new systems designed to fund and deliver programs established to meet vital public policy objectives. These programs include, among others, those designed to assist low- income consumers, to increase the use of low-emission vehicles, to increase energy efficiency and ensure resource diversity within the electric services infrastructure, and to offer rate discounts to businesses to enhance economic growth. (Rulemaking, pp. 47-58.) On August 31, 1994, the California Legislature passed Assembly Concurrent Resolution (ACR) 143. ACR 143 established the Joint Oversight Committee on Lowering the Cost of Electric Services to ensure that the Commission's final proposals meet certain standards and to ensure that the Legislature is properly consulted and involved in electric restructuring policy proposals. The resolution urged us to refrain from issuing a final order until we held evidentiary hearings on the issue of uneconomic utility assets and reported to the Legislature on a series of topics related to restructuring. Written comments on the Rulemaking were filed by 113 individuals and organizations, and five full panel hearings were held between June and October 1994 to elicit further input on electric industry restructuring and regulatory reform.4 Over 90 individuals and organizations participated as panelists at these full panel hearings. In addition, hundreds of California citizens have voiced their opinions on industry restructuring at 16 public participation hearings held from August 1994 through January 1995 throughout the state: Eureka, San Diego, South Lake Tahoe, Stockton, San Francisco, Martinez, San Jose, Fresno, Pasadena, Bakersfield, Ventura, Garden Grove, Carson, San Bernardino, Pasadena, and Huntington Park. These hearings provide the opportunity for any person to share his or her views on electric industry restructuring issues before a representative of the Commission, e.g., a Commissioner or Administrative Law Judge. Many more have been able to participate via Internet access to the full panel hearings and written comments, and through public broadcasts over The California Channel. In order to begin assessing the electric utilities' uneconomic assets and obligations, we also held a week of evidentiary hearings devoted to these issues from December 14 to 22, 1994. 4 Attachment 8 presents a list of individuals and organizations that participated in this dialogue by either filing written comments or presenting verbal testimony at the full panel hearings. A3.4 ATTACHMENT 3 ATTACHMENT 3 On December 7, 1994, we issued an interim decision describing a detailed procedural plan for finalizing our policies.5 This plan solicited further public comment on the sustainability of public policy goals and on implementation issues associated with a broad range of restructuring models. Recognizing the benefit of engaging all stakeholders in the examination of these issues, our decision called for the creation of a working group, comprised of any interested party.6 The working group was asked to submit a report to the Commission on implementation options that enable each of the broad restructuring models to accomplish the following objectives: 1. Unbundling Electric Service: To ensure that the unbundling of electric services (including transmission and distribution from generation) provides clear and accurate market price signals to all market participants and is not unduly discriminatory. 5 Decision 94-12-027. 6 The December 7 decision also requested briefs on the impact of existing state and federal law on restructuring scenarios. Briefs were filed by the following parties: California Cogeneration Council (CCC), California Farm Bureau Federation (Farm Bureau), Center for Energy Efficiency and Renewable Technologies (CEERT), California Manufacturers Association (CMA), California Large Energy Consumers Association (CLECA), Department of General Services (DGS) and Industrial Users (IU), Cogeneration Association of California (CAC), Division of Ratepayer Advocates (DRA), Energy Finance Forum (EFF), Enron Capital and Trade Resources, Inc. (ENRON), Independent Energy Producers (IEP), Modesto Irrigation District (MID), Natural Resources Defense Council (NRDC), New York Mercantile and Exchange (NXMEX), PacifiCorp, Pacific Gas and Electric Company (PG&E), Sacramento Municipal Utility District (SMUD), San Diego Gas and Electric Company (SDG&E), Sierra Pacific Power Company (Sierra Pacific), Southern California Edison Company (SCE), Southern California Public Power Authority (SCPPA), Texaco Inc. (Texaco), Toward Utility Rate Normalization (TURN), United States Department of Energy (DOE), and Western States Petroleum Association (WSPA). A3.5 ATTACHMENT 3 ATTACHMENT 3 2. Public Policy Programs: At a minimum, maintain and continue to encourage the existing level of benefits and services. The goal is to create more efficient and effective delivery mechanisms for public policy programs, not to eliminate public policy programs; perhaps these may be implemented through other governmental agencies or programs. 3. Resource Procurement and Diversity: To pursue and encourage the goals of resource diversity and energy efficiency, as well as to promote environmentally sensitive electric service. 4. Cost Recovery Mechanisms: Provide alternatives to the current form of recovering the cost of public policy programs, environmental programs, uneconomic assets, and utility obligations (and any other component of a competition transition charge) from ratepayers and recommend appropriate recovery mechanisms that least distort the price signals of a competitive market. In response to the reporting requirements of ACR 143, on January 24, 1995, we submitted a status report to the Legislature on electric industry restructuring and regulatory reform.7 Attachments 8 and 9 respond to the questions posed by ACR 143 and our interim status report, based on the draft proposal offered today for comment. 7 Status Report on Restructuring California's Electric _______________________________________________________ Services Industry and Reforming Regulation, prepared in response __________________________________________ to Assembly Concurrent Resolution No. 143, January 24, 1995. A3.6 ATTACHMENT 3 ATTACHMENT 3 The Working Group submitted its report to the Commission and the Legislature on February 22, 1995.8 Highlight of the Working Group Report are presented in Attachment 6. II. Positions of the Parties As articulated in the Rulemaking, our express objective is to establish a new regulatory framework that "does a considerably better job of exerting downward pressure on the prices California's residential and business consumers must pay for investor-owned electric services." (Rulemaking, pp. 5-6.) The Rulemaking proposal was premised on the conclusion that, because the cost-of-service regulatory framework resulted from an organizing principle based on the existence of a natural monopoly, that framework is ill-suited to, and incompatible with, an electric services industry that will face increased competition. With few exceptions, parties agree that current regulatory approaches are unsuitable to meet the challenging changes in the electric industry market.9 In addition, parties generally agree that, under increased competitive pressures, utilities will be motivated to operate more efficiently and reduce costs. This, in turn, is expected to drive utility rates down. 8 Working Group Report "Options for Commission Consideration", in Response to Decision 94-12-027 of the California Public Utilities Commission in OIR. 94-04-031/OII. 94-04-032, February 22, 1995. Special Recognition should be given to Yole Whiting, Kathy Treleven and Dian Gruenich for their invaluable role in coordinating, summarizing, and editing the various written products of the Working Group members and subcommittee into a well-organized, concise report. 9 For example, see: DRA, June 8, 1994 comments, p. iii; Utility Consumers Action Network (UCAN), June 8, 1994 Comments, p. 7.; Wickland Corp. (Wickland), Vol. 11, pp. 1995-1996; Enron Power Marketing, Inc. (EPMI), Vol. 1, pp. 271-272; Environmental Defense Fund (EDF), June 8, 1994 comments, p. 1.; PG&E, June 21, 1994 Comments, p. 2; Agricultural Energy Consumers Association (AECA), Vol. 1, p. 149; Professor Bernard Black, School of Law, Columbia University, Vol. 2, p. 362; NYMEX, Vol. 1, p. 259; DOE, Vol. 2, pp. 424-425; Coalition of Employees, Vol. 1, pp. 199-200; CLECA, June 8, 1994 comments, p. iv; SCE, June 21, 1994 Comments, p. 2; The Greenlining Coalition (Greenlining), June 24, 1994 comments, p. 1.; Senior Utility Ratepayers of California (SUROC), cover letter to July 24, 1994 comments; Farm Bureau, Vol. 11, p. 2011; The City of San Diego (San Diego), June 8, 1994 comments, p. 2; Federal Executive Agencies (FEA), June 8, 1994 comments, p. 2; California Energy Commission (CEC), June 14 transcript on pp. 173-174; and CMA, Vol. 1, p. 140. A3.7 ATTACHMENT 3 ATTACHMENT 3 However, not all parties agree fully with the Rulemaking's assessment of the inevitability and scope of competition. Moreover, parties disagree on how the energy services industry should be restructured to best take advantage of competition, and how that industry should be regulated in the future. The range of views presented during our inquiry reflects parties' concerns about the types of changes that a competitive environment may bring to market participants. In general, these concerns revolve around the following themes: 1. How are the market benefits of increased competition best realized and equitably distributed among all customer classes? 2. How can a restructured market best provide safe and reliable service to its customers? 3. How should nondiscriminatory access to the market be assured for all power producers in a restructured environment? How should restructuring ensure that market power in generation is not overly concentrated? 4. How should the responsibility for uneconomic assets and obligations be allocated among industry participants, and over what period of time? 5. How can a restructured industry adequately accommodate environmental concerns and recognize the benefits of cost-effective demand-side management and resource diversity? 6. How should cost recovery for certain public policy programs, such as low- income rate assistance, economic development, research, development and demonstration, and low-emission vehicles be addressed in a restructured industry? The sections that follow provide an overview of the comments that we have received on these issues. This overview is distilled from transcriptions of our full panel hearings and the written filings. It is intended to illustrate the range of A3.8 ATTACHMENT 3 ATTACHMENT 3 debate about these issues, rather than to serve as a dispositive discussion of each party's position or statement of fact.10 The following sections are organized as follows. Section A below presents the range of proposals for industry restructuring that has emerged from the debate. Section B provides an overview of parties' views on which of these proposals will best realize reasonable rates and reliable service. Section C summarizes parties' comments on how to ensure nondiscriminatory access for all power suppliers in the market. Section D presents an overview of parties' comments on environmental issues, resource diversity, demand-side management, and other issues related to integrated resource planning. Section E discusses parties' comments regarding various public programs, for which the utility has traditionally served as the funding vehicle. Section F describes the options presented by the Working Group for our consideration. Parties' positions on the level and allocation of costs associated with uneconomic assets are described in Section G below. A. Market Structure: Range of Options As described above, the Rulemaking proposal would gradually provide all of California's consumers direct access to the market for electric generation services, on a voluntary basis. The Commission asked parties to comment on whether successful implementation of the direct access proposal depends on the Commission first establishing a centralized, spot market, similar to the system implemented in the United Kingdom. (Rulemaking, p. 26.) In response to this question, participants presented two basic market models for restructuring with several variations: one which would rely on principal-to-principal transactions between retail customers and power producers to establish market 10 Summaries of each party's position, as presented in the four rounds of written comments and a the final full panel hearing, were presented in Volume 2 of our January 24, 1995 report to the Legislature entitled: Status Report on ____________________ Restructuring California's Electric Services Industry and _________________________________________________________________ Reforming Regulation. We solicited written comments on those _____________________ descriptions and, with the exception of minor clarifications suggested by the Western Mobilehome Association (WMA), the Farm Bureau and School Project for Utility Rate Reduction/Regional Energy Management Coalition (SPURR/REMAC), no parties disagreed with the general characterization of their positions in that report. We reflect those clarifications in this document, where appropriate. We also note positions that have been presented subsequent to our request for comments, such as those recently articulated by municipal utilities and by Edison and SDG&E in their supplementary comments. A3.9 ATTACHMENT 3 ATTACHMENT 3 prices (bilateral contracts or buy-sell arrangements) and one which would require a centralized wholesale pool to establish a competitive electricity spot market (Poolco). Either of these approaches may include changes in the utility structure and ownership, such as the disaggregation of the generation and transmission function. Either may also include performance-based regulation. Several additional proposals for market structure emerged from the public dialogue as substitutes for or complements to these models: bulk power (wholesale) reform, the community access model, regional transmission model, and the Tehachapi Compromise. The following descriptions embody the range of proposals for industry restructuring described in written comments and full panel hearings and are intended to be representative of, and not limiting, those under consideration. 1. Model 1: Direct Access via Bilateral Contracts/Buy-Sell Under this model, all retail customers would have direct access to a competitive electric generation market and the ability to contract with the supplier of their choice. Voluntary wholesale pools could develop, but would not be mandatory.11 A 11 Parties who favor this approach include: Agricultural Energy Consumers Association (AECA), American Forest & Paper Association (AF&PA); American Gas Association (AGA); American Wind Energy Association (Wind); Amoco Production Company (Amoco); Association of California Water Agencies (ACWA); British Columbia Power Exchange Corporation (Powerex); Broad Street Oil & Gas Company (Broad Street); California City-County Street Lighting Association (CAL-SLA); CCC; California Energy Coalition; Farm Bureau; CLECA; CMA; Cellnet Data Systems (Cellnet); Chevron Corporation (Chevron); Citizens Power and Light Corporation (Citizens); Coalition for Choice in Electricity (Coalition for Choice); Cogenerators of Southern California (CSC) ; County of Orange; County of Sanitation Districts of Los Angeles; County of Sonoma; the Commission's DRA; Destec Energy, Inc. (Destec); Eastside Power Association (Eastside); Electric Clearinghouse, Inc. (ECI); Electricity Consumers Resource Council (ELCON); Energy Storage Partners (ESP); EPMI; EDF; FEA; Flowind Corporation (FC); IEP; IU; Jefferson Electric, Inc. (Jefferson); Kenetech Windpower, Inc. (Kenetech); Magma Power Company (Magma); Marron, Reid & Sheehy; May Department Stores Company (May); MZA Utility Consultants; National Independent Energy Producers (NIEP); National Rural Electric Cogenerators (NREC); National Utility Service, Inc. (NUS); NYMEX; PG&E; Pacific Generation Development (PGD); Pacific Power and Light Company (PP&L); Philip Morris Management Corporation (PMMC); Portland General Electric Company (PGE); SPURR/REMAC; Sesco, Inc. (SESCO); State of A3.10 ATTACHMENT 3 ATTACHMENT 3 retail customer could either select a supply coordinator (agent), who would be responsible for meeting the needs of its customers, or act as its own coordinator and contract directly with various energy providers. In turn, supply coordinators and retail customers would have access to a variety of power producers, such as independent power generators, power marketers, and other utilities. Those retail customers who chose not to buy disaggregated services or contract with an agent could continue to buy bundled service from their local utility. The local utility in this structure (sometimes referred to as the local distribution company (LDC)), would provide access to electricity supplies to all, and provide generation services to those who chose to remain full service customers. Services and prices for electric services would be unbundled (e.g., disaggregated into generation, transmission, and distribution functions) to provide clear price signals to customers. Investor-owned utilities (IOUs) would be obligated to provide nondiscriminatory transmission and distribution services to direct access customers and their agents. However, IOUs would not be required to plan for, construct or contract for generating resources to meet customer demand for those customers electing direct access. Competitive forces in the energy services market would determine the amount and type of new generation capacity that will be built. Proponents of this approach suggest that Federal and state laws determine environmental requirements, but market forces would determine how to meet the requirements. Under this model, an independent entity (rather than the IOU) would serve as the grid operator, maintaining system reliability, managing grid emergency responses, and settling imbalances. The system coordinator would require a minimum amount of generating resources subject to the coordinator's control in order to maintain the integrity of the system. However, the grid operator would not serve as an economic dispatcher of the power entering the system. The economics of power production would be influenced by the price established by numerous bilateral agreements. Price revelation tools and financial hedging instruments would develop without regulatory guidance. In instances of transmission constraints, access priorities would be established by the independent grid California, Department of General Services (DGS); State of California, Department of Water Resources (DWR); Southern California Gas Company (SoCalGas); Texaco, Inc. (Texaco); U.S. Borax Inc. (Borax); Watson Cogeneration Company (Watson); Western Mobilehome Parkowners Association (WMPA); WSPA; Wickland; and Zond Systems. Inc. (Zond). A3.11 ATTACHMENT 3 ATTACHMENT 3 coordinator according to rules approved by the Federal Energy Regulatory Commission (FERC). Congestion pricing in the transmission market would provide the mechanism to signal the need for new transmission facilities. Proponents expect that a Regional Transmission Group (RTG) would coordinate the planning of new transmission facilities on a regional basis, based on the requests of grid users. The transmission owner, upon request, would build any new transmission facility that is fully funded by grid users, subject to regulatory review. An alternative to bilateral contracts that creates the same market structure is the "buy-sell" approach suggested by the CMA.12 Under CMA's buy-sell proposal, the utility would purchase generation services on behalf of the direct access customer from the generation service provider designated by the consumer. The utility would receive a fee for the "buy-sell" service provided. In addition, the utility would secure any transmission services necessary to deliver power from the designated service provider to the consumer. There is wide disparity among proposals about when all customers would be eligible for direct access service or buy-sell arrangements. Under the Rulemaking proposal, direct access to a competitive retail market would be phased in starting with the largest customers in January of 1996. All customers would have direct access by 2002. Another proposal would have direct access phased in over 12 years, starting with the largest customers. All customers would have access to a retail market by 2008. Other proposals for direct access would implement direct access concurrently for all customer groups or a portion of all customer groups.13 Several parties request that the Commission allow self-service wheeling arrangements, particularly if implementation or phase in of retail direct access is slowed.14 12 The alternative strategy is designed to avoid the jurisdictional uncertainties and spectre of federal preemption that some parties assert the Rulemaking's approach to direct access creates. See Fourth Round Comments of the California Manufacturers Association, August 23, 1994. 13 For example, SPURR/REMAC proposes a pilot program for public school, electric purchases in addition to large industrial users, beginning in 1996. 14 Self-service wheeling allows entities with their own generating facilities to wheel that generation to service their own electric load at remote locations. Parties proposing Commission's consideration of this variation include: DGS, CCC, Borax, and Chevron. A3.12 ATTACHMENT 3 ATTACHMENT 3 2. Model 2: Mandatory Centralized Power Pool (Poolco) Proponents of this model would reform the energy services market by establishing a new, federally-regulated centralized pool in which all power sale and purchase transactions must occur. Parties who initially responded to the Rulemaking proposal by advocating a single, mandatory Poolco structure include Edison, SDG&E, CEC, US DOE, and academics and consultants.15 Under this approach, customers could purchase power at the pool spot price, or make other financial arrangements with third parties for "contracts for differences." Third party providers (e.g., brokers and agents) could also make these purchases and financial arrangements on behalf of customers. All electric power producers would compete in the generation market by submitting bids to the pool. The highest winning bid becomes the market-clearing price and is offered to all sellers who bid below it for each hour or half hour each day. The Poolco would serve as an independent system dispatcher separate from the ownership of the transmission assets.16 The independent operation of the dispatch function would maintain system reliability, e.g., avoidance of voltage collapse, instability, and frequency control, and balancing power production with power consumption. This function would be similar to that of the independent grid operator under the bilateral contracts/buy-sell model. Proponents of the Poolco also envision that new transmission investments would be coordinated through an RTG, as described above. However, unlike the bilateral contracts/buy-sell model, the Poolco would also establish competitive bidding procedures to determine which plants are dispatched at any given time. All power providers would be paid a single uniform "market clearing" price. That price would be equivalent to the bid price offered by the highest winning bidder. Prices determined by Poolco's 15 These include Professor William Hogan of Harvard's Kennedy School of Government and consultant to SDG&E, Professor Paul Joskow of MIT and consultant to Edison, and Sally Hunt of the National Economics Research Association and consultant to Edison. 16 The price setting function and system coordinating function could exist within a single Poolco structure (as proposed by Edison), or they could exist as a separate Poolco for price-setting and a "Gridco" for coordination, as proposed by SDG&E. For ease of discussion, we assume a single Poolco structure encompassing both the coordination and pricing functions. A3.13 ATTACHMENT 3 ATTACHMENT 3 competitive bidding program would vary half-hourly, hourly, or in whatever increments Poolco (and FERC) found the most appropriate. Contracts for differences would be accommodated outside of the pool. These transactions would be private, unregulated, and available to wholesale and retail customers. They would act as financial hedging instruments to reduce the risk of price volatility in the pool over the long term. For example, an electric power producer and customer might have a contract for 1,000 kilowatt hours (kWh) at 2 cents/kWh. If the pool spot price is 2.5 cents/kWh, the customer would pay 2.5 cents/kWh to the pool, the pool would pay 2.5 cents/kWh to producers that were dispatched into the pool, and the producer would pay a credit of 0.5 cents/kWh to the customer based on the difference between the contract price and the pool price. Conversely, if the pool spot price is 1.5 cents/kWh, the customer would pay the producer 0.5 cents/kWh. These transactions would occur even if that particular producer is not dispatched to deliver power into the pool. Third parties could also make these types of financial arrangements with retail customers. Proponents of this model expect that the pool functions would be regulated by FERC. IOUs would continue to distribute power to customers, and distribution would remain a California Public Utilities Commission (CPUC) regulated monopoly function. Poolco proposals differ in terms of how retail customers would gain access to pool prices. Under the variation proposed by Edison, the retail customer would be able to buy directly from the pool. SDG&E and others would require customers to go through the utility to purchase from the pool on their behalf. 3. Model 3: Bulk Power (Wholesale) Reform Some parties, including SMUD, SCPPA, NRDC, Coalition of California Utility Employees (CUE), American Public Power Association (APPA), and International Brotherhood of Electrical Workers (IBEW), recommend that reform focus on developing transparent information in the bulk power (wholesale) market. Under this approach, California would make improvements to the existing bulk power market to lower the cost of electricity. These would include FERC approval of open access tariffs, completion of the Western States Power Pool daily energy board and development of IOU daily transmission and pricing bulletin boards. This model retains utilities--both public and investor- owned--as resource portfolio managers for their service territories. It does not at this time contemplate that retail customers who seek electricity service through the integrated grid would bypass their host utility. 4. Model 4: Community Access Model TURN proposes that community entities be allowed to purchase electric services at the wholesale level on behalf of retail customers within that community.17 Cities, counties, water A3.14 ATTACHMENT 3 ATTACHMENT 3 districts, and other local entities would be authorized by legislation to establish consumer-owned utilities or cooperatives (COUs) over a defined geographic area. Unlike municipally-owned utilities, COUs would not actually acquire distribution facilities or any other physical assets. COUs would act as brokers between the community, the utilities, and competitive power supplies. All classes of customers would be eligible to participate at the same time. COUs would aggregate the loads of all the residents and businesses within the geographical area. COUs would be responsible for forecasting need and purchasing the necessary power from the many wholesale suppliers who would compete to supply all or a portion of the COU demand, e.g., municipal utilities, nonutility generators, exempt wholesale generators, power marketers, and energy service companies. COUs would engage in purchasing energy on behalf of the whole community, which includes residential, commercial, and industrial customers. COUs would then set their own rates for their customers. COUs would purchase distribution and other services from the local IOU at Commission regulated rates. IOUs would be phased out of the power generation business. As proposed by TURN, this variation would not allow individual customers to leave the utility and choose among competing generation service providers either by entering into bilateral contracts or making buy-sell arrangements with the utility. 5. Model 5: Regional Transmission Model An alternative proposed by CEERT would create a regional monopoly for transmission services. Under this approach, the IOUs would be required to sell their transmission assets to either a public or investor-owned entity. The transmission entity would perform economic dispatch and provide grid support. Generation would become a competitive commodity with cost recovery for existing and new generation facilities subject to market risk. In order to finance the transition to this industry structure, the net gain from the sale of undervalued IOU transmission assets would offset the costs associated with the IOUs' uneconomic generation assets or retiring the appropriate revenue bonds for municipally-owned generation. This would allow existing generation assets to be removed from ratebase and subject to market recovery. At the same time, existing contracts for generation would be renegotiated or bought out. This 17 The City of Palm Springs also proposes a similar community access model as outlined in a letter to the Commission on December 15, 1994. A3.15 ATTACHMENT 3 ATTACHMENT 3 proposal requires financial decoupling of monopoly distribution from competitive generation. The distribution function would remain a local monopoly with jurisdictional utilities providing distribution services. The Commission would continue to regulate investor-owned distribution utilities, while municipal utilities remain under current regulation by political entities. As proposed, this variation would not preclude other proposals for direct access or a central pool. 6. Model 6: Tehachapi Compromise Dr. Philip O'Connor of Palmer Bellevue, supported the Cities of Burbank, Glendale, Pasadena and Imperial Irrigation District advocate a compromise between the mandatory pool model and the bilateral market model without a mandatory pool. Under the "Tehachapi Compromise," both would be allowed to proceed simultaneously in different service territories. This approach is suggested as an experiment with both models beginning concurrently and on parallel schedules in order to allow an accurate evaluation of their merits. Two approaches for this compromise have been presented. One would defer the introduction of the bilateral market in both northern and southern California until the mandatory pool model is ready to be implemented. The other approach is to set a short time frame for implementation of the bilateral program in the north and for implementation of the pool in the south. If there is a delay in implementation of the pool program, then the participants in the south could make bilateral arrangements. These participants would not be required to participate in the pool if they chose to continue participating in the bilateral program. B. Reasonable Rates and Reliable Service As described above, some parties believe that incremental reform of the bulk power market would best achieve the Commission's goals. Under this approach, reform would consist of establishing PBR for the utility's bundled procurement of energy services and optimizing the bulk power market through open access transmission and unbundled prices. Proponents of bulk market reform argue that this approach provides significant efficiency benefits to the system, avoids jurisdictional battles with FERC, allows the current mechanisms for integrated resource planning and for delivering public policy programs to continue, and distributes benefits equally to all customer classes. Most parties argue that bulk power reform initiatives alone are not sufficient to achieve the Commission's goals, and that retail customers should be given choice as part of the reform initiative. However they are not in agreement on what form that choice should take. As described above, most parties argue that retail choice should take the form of principal-to-principal arrangements with suppliers (bilateral contracts or buy-sell A3.16 ATTACHMENT 3 ATTACHMENT 3 arrangements). Others argue that establishing a "virtual direct access" system consisting of a mandatory wholesale pool and contracts for differences will provide meaningful choice. Many parties agree that a system consisting of both pool arrangements and bilateral contracts can coexist.18 However, parties in favor of a bilateral contracts/buy-sell market believe that it is not necessary to establish a pool before providing direct access to retail customers. They predict that pools will develop on their own, if market participants find them valuable. Advocates of bilateral markets/buy-sell believe that the electric services industry already contains the essential ingredients for a vigorous competitive market. There are many consumers of such services, and many providers from whom an increasingly broad array of products and services are available. They note that information and transmission technology exist to enable ready access between consumers and providers. Bilateral market proponents assert that restricting competition by limiting it to the wholesale level or within a government-created pool is not a true market-based solution. They believe that wholesale competition alone will do little to further the Commission's goal of lower prices to all consumers and that a competitive wholesale market will produce only lower wholesale prices. Moreover, these parties argue that the Poolco price will be uniform and not allow customers to seek out lowest-cost providers. Parties supporting the Poolco model believe that customers can obtain "virtual direct access" to a competitive supply market if they can buy electricity at a price that is visibly linked to the real-time spot market price of electricity generated for sale in California. As proposed, once the Poolco is established, the spot price seen by wholesale sellers and buyers can also be provided to all retail customers. Once customers have access to a real-time spot price, they can continue to buy electricity at that price, or enter into a financial hedging contract with any party. In this way, Poolco proponents argue, consumers can tailor any deal which might otherwise occur under bilateral 18 For example, SCPPA, whose members include Anaheim, Burbank, Glendale, Los Angeles, Pasadena, Riverside, Vernon and Imperial Irrigation District, recently made public a Multiple Choice Model (McPool). The model proposes both voluntary participation in a power pool and bilateral arrangements for wholesale entities. On February 23, 1995, Edison and SDG&E jointly submitted a description of their Poolco proposal that would also have voluntary pooling and bilateral arrangements functioning side by side at the retail level at some future, but unspecified, date. See Supplemental Comments of San Diego Gas & ________________________________________ Electric Company and Southern California Edison Company On _________________________________________________________________ Competitive Markets and Appropriate Market Institutions In a _________________________________________________________________ Restructured Electric Industry, February 23, 1995, p. 18. ______________________________ A3.17 ATTACHMENT 3 ATTACHMENT 3 arrangements. The end result, in their view, is that all consumers will benefit from competition under the mandatory Poolco approach sooner and in a more equitable manner than under the Rulemaking proposal.19 The issue of economic dispatch has drawn disparate views from many parties. Parties supporting the pool model clarify that a pool would provide for the economic, least-cost use of generating capacity so long as the generation market is competitive and the pool provides transmission access on a nondiscriminatory basis to all generators seeking to sell power in California. At any given time, the least-cost mix of generation would be used to serve California's electricity needs, taking into consideration any transmission constraints. They believe that the pool would achieve the equivalent of economic dispatch on a statewide basis, as compared to the current system where economic dispatch is generally performed only on a utility system basis. Furthermore, they believe that generators would have a strong incentive to operate their plants efficiently because economic dispatch would give them the incentive to operate units only when it is economic to do so and lower their costs to ensure that they are competitive. Thus, pool proponents conclude that economic dispatch provides an overall benefit to all customers because it results in downward pressure on the spot price of power. Pool proponents believe that dispatching on a contractual basis would not be economic. They argue that a bilateral market will exacerbate dispatch problems because the grid operator may have to purchase higher cost power instead of lower cost power, and encounter minimum load problems. They also assert that price visibility and market information are lacking in a model based on bilateral contractual arrangements. They believe a centralized pool is preferable because it provides a visible spot market price at all times. In addition, proponents argue that the judicial system is ill-equipped to manage what would likely amount to a growing number of contract disputes arising from an increased number of commercial arrangements. Those who advocate a model based on bilateral contracts or buy-sell arrangements prefer a system of numerous commercial agreements with opportunities for trading and brokering to a system of central bidding. They recognize the need for coordination and balancing/settlement services, provided by the operator of the transmission system. However, instead of economic dispatch by a pool operator, they believe that a market system of contracts and brokers provides more than sufficient incentives for efficient operation. They note, in response to 19 In their February 23, 1995 supplemental comments, Edison and SDG&E project that Poolco may be operational as early as January 1, 1998. A3.18 ATTACHMENT 3 ATTACHMENT 3 proponents of pools over bilateral contracts, that the notion of economic dispatch is stretched by the idea that generators (backed by contracts for differences or other financial arrangements) can submit zero bid prices in order to influence their dispatch in pool systems. In their view, concerns over uneconomic operation in a system of bilateral agreements is best resolved by open systems of efficient market instruments. They believe that with brokers allowed to match consumers and producers, few, if any, occasions of uneconomic dispatch can occur. In addressing whether retail customers are equipped to participate in this market absent some mandated pool price reference, bilateral market proponents assert that a price reference will quickly develop on its own, based on experience from other industries. They conclude that allowing the market to develop at its own pace will enable retail customers to enjoy customized risk management at the lowest possible cost. They also argue that cost and technology limitations in installing real-time meters and billing systems for all retail customers will require a phased-in approach to providing retail choice, and not provide the comprehensive access to spot market prices that mandatory Poolco proponents assert will be available in 1998. Proponents of the bilateral contracts/buy-sell approach also express considerable skepticism about reliance on government's ability to use an administrative process to establish the specific mechanisms and institutions necessary to ensure a smoothly functioning market. Drawing on evidence from the United Kingdom (UK) experience, they argue that the incentives embedded in the UK pricing and payment regime encourage power providers to submit bids which systematically exceed marginal cost, resulting in higher prices to consumers, undesirable signals to market participants and decreased efficiencies generally. They also assert that granting a new, monopoly franchise in the bulk power market represents further centralization that runs contrary to national public policy reforms. Parties in favor of bilateral markets also argue that by the time the customer gets the price signal from the pool, it is "too late" to make changes in operating systems or have control over loads. They believe that electric consumers will gain from lower overall costs and greater operating efficiencies that come from their ability to take advantage of options for power purchases. They foresee that bilateral markets will allow customers and power producers to creatively rebundle packages of both existing and new services. These parties also predict that economic efficiency will improve when customers have the ability to mix a set of products and services instead of receiving "vanilla flavored" electric power. Concerned that a market based on bilateral contracts may benefit a few select suppliers and customers at the expense of other customers, many pool proponents are not confident that A3.19 ATTACHMENT 3 ATTACHMENT 3 retail direct access will provide meaningful benefits to small customers, particularly residential customers. Others point to full panel hearing participants who are marketers and who have expressed interest in serving residential customers. They argue that electric service needs are not homogenous among residential users and that the load profile differences between residential and commercial customers will work to the advantage of both. In the debate over the reasonableness of rates under bilateral contracts versus mandatory pools, many parties expressed some concerns over when specific customer groups would gain access to the competitive market under the Rulemaking proposal. The Rulemaking proposal would phase-in direct access, beginning January 1, 1996 for large industrial customers. All customers would be eligible for direct access by 2002. (Rulemaking, pp. 37-38.) Some believe that a phased-in schedule for eligibility over a long period of time, starting with large consumers in advance of small/residential consumers, is discriminatory. They are concerned that a phased-in schedule for eligibility will allow customers who initially participate to take advantage of all the low-cost opportunities that exist, leaving none for customers who are subsequently phased-in. Another concern is that keeping some customers captive to bundled utility service for a long time will leave them vulnerable to cost-shifting. Specifically, they see utilities reserving their lower cost generation resources for their direct access customers, while leaving the regulated customers with the burden of paying for their higher cost generation. To address these concerns, some parties propose the phasing- in of a cross-section of customers from all customer classes, including an aggregation program for smaller customers. Several parties believe that the Commission should abandon its phase-in proposal altogether and allow all customers access to a competitive supply market. In their view, smaller customers could be served by independent marketers or aggregators who would be able to negotiate with suppliers from a bargaining position similar to large consumers. Under the Community Access Model, municipalities and similar political subdivisions would become agents or aggregators for the residents and businesses within their boundaries. As described above, a few parties advocate a compromise between the mandatory pool model and the bilateral market model without a mandatory pool by simultaneously allowing both to proceed in different service territories. This compromise is based on the belief that the market will decide which approach best meets the needs of stakeholders. Such a compromise has been described by proponents as the path of least resistance which avoids contentious and drawn out debate. Uncertainties such as jurisdictional issues, transmission and distribution pricing, and availability of technology would be resolved with time under implementation of both models. This proposal is suggested as an A3.20 ATTACHMENT 3 ATTACHMENT 3 experiment and as such, it is stressed that both experiments should begin concurrently and on parallel schedules in order to allow an accurate evaluation of their merits. Some parties believe that the compromise ignores the fact that the grid system is interconnected and argue that imposing two very different requirements concurrently would be impractical. They are further concerned that competing businesses that are electric consumers in different service territories may be unfairly affected. Proponents of the compromise acknowledge criticism but believe that there would be no greater level of dissatisfaction than if a single program were imposed for the state. In their view, rather than implementing a single model using only the past regulatory framework for comparative evaluation, a compromise of two models would provide more meaningful information. As for safety and reliability, parties opposed to the bilateral market approach argue that it would introduce high risk to operational reliability. Proponents of bilateral contracts counter that an effective scheduling and nomination process can be developed by the system grid coordinator (without requiring a pool) to enable the coordinator to know who is on or off the system on a real time basis. In addition, proponents of a bilateral market argue that the transmission tariff could require 24-hour dispatch capability or other conditions to ensure system reliability. They point out that the electric services industry in the West is currently organized around a sophisticated combination of voluntary pooling arrangements and bi- and multi- lateral contractual arrangements that have acted to increase, not lessen, system integrity, reliability of supplies and increased efficiencies. In general, parties express concern that there needs to be a more complete statement as to how system reliability will be accomplished under any of the proposed models. Increased competition, whether through a pool or through bilateral transactions, could dramatically increase the number of participants and make operation, coordination, and planning of generation and transmission facilities and services more difficult. Some raise the issue of how "must run" resources, including contracts with qualifying facilities (QFs), will be accommodated under either model. Others are concerned that in a more competitive market, utilities may reduce cost by cutting back on safety measures that currently ensure the safe operation of utility plants. C. Nondiscriminatory Transmission Access/Anti-competitive Concerns In our Rulemaking, we recognized the need to foster the expeditious development of fair and open transmission access. (Rulemaking, pp. 38-40.) We also recognized that A3.21 ATTACHMENT 3 ATTACHMENT 3 nondiscriminatory access requires, at a minimum, the accounting separation of functions to ensure that there is no cross- subsidization across utility products and services.20 These issues were also recognized in written comments and oral testimony at the full panel hearings, as summarized below. In addition to concerns of how customers will share in the benefits of competition, parties also expressed concerns over how nonutility suppliers will gain nondiscriminatory access to a restructured, competitive market. While a growing number of utilities have filed open-access transmission tariffs, APPA, DRA, FEA, and others argue that open, nondiscriminatory, and comparable access still does not exist for all generators in all regions. These parties believe this is a critical step toward the achievement of nondiscriminatory access for all wholesale buyers and sellers, particularly those who do not own transmission. Most parties believe that under any restructuring model, utilities must be indifferent to the source of power transmitted over their power lines and that market power in generation must not be overly concentrated. Many are concerned that if utilities do not divest their generation assets, there would be a potential for self-dealing and cross-subsidy.21 They argue that allowing the utility to remain in the commodity business within its service territory would force the Commission to adopt stringent and onerous safeguards to ensure against anti-competitive behavior and self-dealing between the utility's sales and distribution functions. They assert that the safeguards necessary are likely to be sufficiently onerous to thwart one of the Commission's key objectives of streamlining regulation. Several parties express concern that the benefits of competition may not be realized under any model of restructuring if only a few entities, utility or third-party (via divestiture) retain significant control over generation facilities. In contrast to these calls for divestiture, SDG&E and Industrial Users see the creation of subsidiaries as a viable resolution of these issues. SDG&E proposes to reorganize into a holding company and create a wholly owned generation subsidiary. Others, including CSC, Sierra Pacific, and PacifiCorp, believe 20 However, our Rulemaking proposal does not require divestiture of generation assets. See Rulemaking, Appendix A, Policy Summary 13 and 23. 21 Parties arguing that the utility must exit altogether the market for generation services within its service territory include: AES, AF&PA, Wind, CCC, CEERT, CLECA, CMA, Conservation Law Foundation (CLF), DGS, DOE, DRA, Direct Electric (DE), ENRON, IEP, Jefferson, Magma, National Power (PLC), Sierra Club and TURN. A3.22 ATTACHMENT 3 ATTACHMENT 3 that FERC accounting protections eliminate the need for divestiture. The Cities of Burbank, Glendale, and Pasadena believe that divestiture is premature, and suggest that the Commission await FERC's principles on comparability of service. Most parties agree that operation of transmission should be separated from generation to ease concerns about the fairness and efficiency in enhancing competition in wholesale markets. They see many difficult issues arising when ownership or control of generation and transmission facilities resides with the same entities, particularly if regulatory oversight over generation is reduced. They emphasize that increased competition in generation and the unbundling of transmission service will require increased cooperation and coordination among transmission operators because there will be a larger number of more diverse buyers and sellers. Some parties argue that increased nonutility access to transmission requires transmission owners to expand their planning efforts beyond meeting their own needs or for regional reliability alone. One pool proposal adds a cost component to the commodity charge to reflect transmission constraints in the pool price, i.e., locational pricing. It is asserted that this pricing method would encourage more efficient expansion of and provide accurate price signals for the transmission system. Although, as proposed, a centralized pool would be operated by an independent entity, CEERT and others question whether this pool would be sufficiently independent since most of California's transmission facilities are owned by utilities. The economic interests of those owners are viewed as potentially hampering the independence of pool managers and the pool's ability to provide comparable services to those generators who do not own transmission facilities. Some parties comment on the difficulty of divesting any portion of the utility business, whether it is generation, transmission, system operational control, or distribution. They note that divestiture might be difficult and costly to reverse if it proved to be less efficient. Some believe that the utility structure might evolve naturally as a result of market-based decisions. D. Resource Diversity, Demand-side Management (DSM), Environmental Issues, and Other Issues Related to Integrated Resource Planning In our Rulemaking, we propose that integrated resource planning be achieved in "a new, more effective and less burdensome way." (Rulemaking, p. 50.) With respect to utility service customers, we anticipated that each of the utility's PBR initiatives would focus directly on "exploiting opportunities to increase the efficiency with which energy services are delivered and consumed." We expressed our expectation that PBR initiatives would include a regulatory mechanism that breaks the link between A3.23 ATTACHMENT 3 ATTACHMENT 3 utility sales and revenues, by focusing on lost revenues directly attributable to energy efficiency programs. With respect to direct access consumers, we articulated the belief that market incentives would encourage both the utility and independent energy efficiency service companies to compete aggressively to provide services. We proposed to forgo, on a trial basis, reliance on a decoupling regulatory mechanism for utility service to direct access customers.22 (Ibid., p. 54.) With respect to renewable resources and resource diversity, the Rulemaking proposal would allow customers to choose directly among "green" electric service providers, marketers and brokers, just as consumers currently choose, for example, among a wide variety of products using recycled materials and "socially responsible" investment portfolios. (Ibid., p. 53.)23 In the Rulemaking, we invited proposals for alternative frameworks that allow consumers to choose directly among products and services to achieve particular public policy objectives, such as enhanced air quality, energy efficiency and increased fuel diversity. In response, a number of parties including EDF and NRDC express concerns that a "let the market decide" approach may fail to adequately balance system requirements and societal goals associated with resource procurement. Others, including the CMA, Coalition for Choice, DRA, and IU believe that the continued pursuit of California's renewable and fuel diversity objectives is fully compatible with a restructured electric services industry, because these objectives are integral to rational energy resource planning in a competitive environment. Some parties predict that the effect of a competitive supply market based entirely on spot fuel costs will likely be increased electric power imports, rather than the development of indigenous renewable resources. They argue that these power imports might, in the short term, avoid in-state emissions but at the cost of lost California jobs and economic development. NRDC and DRA suggest that a fully competitive generation market should 22 This decoupling mechanism, called the electric revenue adjustment mechanism (ERAM) is a ratemaking mechanism that guarantees utility recovery of authorized revenue requirement, independent of actual energy sales. The utility cannot achieve higher revenues or profits by promoting higher sales relative to the sales forecast. Conversely, the utility will not lose revenues or profits if energy efficiency programs produce greater savings than forecasted. 23 The Rulemaking recognizes that aspects of its proposal may require reexamination of current laws, such as the requirement to set aside a portion of the utility's infrastructure investment for renewable resources. (Rulemaking, p. 53; see also Section 7.0 below.) A3.24 ATTACHMENT 3 ATTACHMENT 3 establish competition based on prices which internalize environmental and other public policy costs. Others argue that environmental issues should be dealt with as they are in other basic industries, through emission control standards and other mechanisms. Several parties raise the question: What alternative mechanisms are available to continue to achieve the benefits of energy efficiency in a restructured world? CMA, DRA, ELCON, and Jefferson believe that if DSM can be made to be a real market with willing buyers and sellers it would work better than it has historically. They suggest that in a competitive retail market, utilities and competitive service providers might offer packages to direct access customers that include DSM services. Critics of this view, including CEC and US DOE, believe it is unclear whether a vigorous energy services market would develop in a direct access environment due to market forces alone, or how PBR coupled with a more competitive retail electricity market would affect incentives for utilities and other providers to pursue DSM. Some believe the market will remain vibrant only if the Commission creates other financing and delivery mechanisms for DSM. There are also divergent opinions on whether the costs of DSM should be borne as a surcharge or included in the distribution price, assuming that utilities continue to fund DSM programs. Some believe that within a competitive market, the full cost of both environmental and DSM efforts should not be bundled with the overall operating cost of the electric system but be included in the utility's distribution price as a visible and independent cost or line item. One party pointed out that this approach might prevent special interest groups from hiding the costs of these efforts within a rolled-in rate and allow for a clear public policy debate on the real cost/benefit of achieving these objectives. Some parties comment that real-time pricing will allow customers to see the value of DSM investments. Many parties argue that any restructuring proposal must consider environmental costs and avoid undercutting the environmental programs in place. They also add that all customers should continue to pay their fair share of these programs. Others contend that emissions taxes, subsidies, and tradeable allowances are better mechanisms to accomplish the goals of valuing cleaner air. They favor the elimination of current subsidy programs and seek reform at the federal and state legislative level. Some parties have suggested that a pollution index be created and included in the price of energy. Pool proponents believe that a pool would provide a means of achieving environmental policy objectives. Some propose that this responsibility could be added to the pool's dispatch function, just as transmission-related constraints affect the dispatch order in today's power pool. The regional pool price A3.25 ATTACHMENT 3 ATTACHMENT 3 would reflect the cost of environmental externalities associated with electric generation. With respect to green pricing, some parties do not have confidence that green service opportunities will adequately incorporate all of the external benefits to the state, the region, and the nation that renewable resources offer. Another criticism of green pricing is that it is unlikely to succeed because the distribution utility cannot direct the product to individual electric consumers. As for fuel diversity and the development of renewable resources, many parties advocate that economically justifiable technologies should be promoted. But there is no agreement as to whether policies ought to encourage uneconomic technologies. Some suggest that fundamental questions must be addressed: What policy guidelines and timelines need to be set to support the development of those renewables that are not cost-effective? Should there be tax benefits at the producer level to stimulate renewables? What is a reasonable premium for buying diversity or reliability insurance? A few parties strongly support portfolios that either automatically included renewables to complement the operational characteristics of the other resources or that are legislatively mandated to contain a portion of renewables in the mix. While parties are at odds as to whether transmission or distribution line item surcharges make economic sense, many believe that targeted and reduced funding for specialized programs that minimize the impact on competitive rates would be required. A few parties question whether the Commission is the appropriate body to tackle this issue; they suggest that the Commission's role has diminished and should focus on ameliorating market barriers, not funding the actual programs. E. Broader Social Objectives In our Rulemaking, we expressed continued support for mandates designed to support important social goals, such as investment in electric and other low-emission vehicles, subsidized rate structures to promote economic development, and programs to assist low-income consumers. We proposed, however, to reexamine the appropriateness of the utility as the principal agent for designing, implementing, and bearing the costs of programs that achieve these broader social goals. Many parties believe that the Commission and Legislature, in their efforts to restructure the electric industry, must rethink how to achieve the goals of these programs and how to structure effective delivery mechanisms. Others, such as PG&E, argue that electric industry restructuring is not the appropriate forum within which to examine these issues. California/Nevada Community Action Association CAL/NEVA, IEP, PG&E, Sierra Pacific, and UCAN propose that the administration of both these social programs and environmental A3.26 ATTACHMENT 3 ATTACHMENT 3 programs continue to be the responsibility of the utility, administered at the utility-owned and operated distribution function. TURN, IU, ELCON, Coalition for Choice, CMA, and CLECA suggest further examination by the Commission, Legislature, and other stakeholders of alternative funding mechanisms with the possibility of end-user surcharges or funding through the State's general fund. Others, including DRA, PG&E, and Sierra Pacific, propose that the costs of these programs be collected through a line-item surcharge on the electric bill of all customers. There was unanimous agreement that California Alternative Rates for Energy or "CARE" was a program to keep.24 However, there is no agreement that the utility should be the administrator of the program. Coalition for Choice and ELCON suggest that the CARE program should be structured like the food stamp program. They argue that food growers themselves do not organize the food stamp program. Multiple parties argued that a decrease in rates would provide greater overall benefits to all customers. One party suggested the elimination of the 10% CARE discount if rates were to decrease by 25%. The Greenlining Coalition and others believe that direct access might result in low-income people paying higher prices due to lack of bargaining power or education. Low-income groups would not be viewed as a lucrative market to competitive service providers leaving the utility to be their only service provider. These parties are concerned that direct access could threaten rate discounts and weatherization programs for low-income households because the utility would have a disincentive to subsidize of these programs in a more competitive environment. The majority of comments on economic development issues were made at the Commission's second full panel hearing where it was emphasized that federal and state policies should be aimed at stimulating increased efficiency. Parties were quick to show that electricity and productivity affect the competitiveness of California businesses. Utilities clearly work with local governments to attract and maintain business with incentive rates, the cost of which are borne by other ratepayers. It was not clear, however, how much utility participation or partnership ________ is needed to promote economic development. F. Uneconomic Assets and Obligations In the Rulemaking, we recognized that utilities may face a disadvantage entering into a competitive environment because of outstanding liabilities that make the price of their electricity higher than market prices. We proposed that direct access customers contribute to the uneconomic portion, if any, of the 24 This program to assist low-income ratepayers with their utility bills was formally called the Low Income Assistance Program (LIRA). A3.27 ATTACHMENT 3 ATTACHMENT 3 utility's generating assets resulting from our new competitive framework. Direct access customers would make that contribution in the form of a "competition transition charge" (CTC) assessed as a separate line item on their bill. The utility would need to compete with other suppliers, however, for those revenues tied to the economic portion of the utility's generating assets, and any overhead tied to the delivery of generation services. We proposed that uneconomic generation costs be calculated as follows: We propose to use the utilities' system marginal cost of generation to determine the market value of each ____ utility plant. Individual plants whose marginal cost falls below the system marginal cost will have a positive market value; those whose marginal cost exceeds the system's will have negative market value. If the net difference between the utility's stock of economic and uneconomic assets is positive, then there is a gain to be distributed between consumers and shareholders. If the net difference is negative, those losses will be reflected in the "competition transition charge" assessed to each customer's demand charge. When assessing the charge, we propose not to allow any class' overall allocation of generation costs or amortization schedules to exceed current levels. In response to ACR 143, the Assigned Commissioners issued a ruling on October 28, 1994 scheduling hearings for December 14 through December 22, 1994. The ruling directed the electric utilities to submit testimony describing their definitions of uneconomic assets and obligations, the items which they would include in the calculation and recovery of the competition transition charge and why. The utility testimony would provide "estimates of the amount of uneconomic assets and obligations and the methodology used and assumptions behind those estimates," propose a CTC which would result from those estimates, and "propose an allocation of those charges among shareholders, classes of ratepayers, and direct access and utility service customers." A3.28 ATTACHMENT 3 ATTACHMENT 3 In their testimony, the utilities and several other parties provided preliminary estimates of uneconomic assets based on their proposed ratemaking treatment and numerous underlying assumptions.25 Table 1 shows the utilities' estimates. Table 2 shows the estimates of other parties. Graphs 1 and 2 show PG&E and Edison estimates performed by Edison, PG&E, and DRA, assuming various market prices. 25 The following parties filed testimony during the December hearings: CCC, CEC, Farm Bureau, CLECA, CMA, CMUA, CAL/NEVA, CEERT, CAC, DGS, DRA, EFF, IEF, IU, ICA, Jefferson, A&ANP, Pacificorp, PG&E, SDG&E, Sierra, Edison, TURN, and Watson. A3.29 ATTACHMENT 3 ATTACHMENT 3 INSERT TABLE 1 HERE A3.30 ATTACHMENT 3 ATTACHMENT 3 INSERT TABLE 2 HERE A3.31 ATTACHMENT 3 ATTACHMENT 3 INSERT GRAPH 1 HERE A3.32 ATTACHMENT 3 ATTACHMENT 3 INSERT GRAPH 2 HERE A3.33 ATTACHMENT 3 ATTACHMENT 3 INSERT LIST OF ASSUMPTIONS A3.34 ATTACHMENT 3 ATTACHMENT 3 The utilities' estimates of uneconomic assets and those of the parties differ substantially due to different assumptions with regard to the components of the CTC, discount rates, future market prices, plant load factors, and other circumstances. The utilities' estimates of uneconomic assets generally include the costs of uneconomic generating capital costs and expenses, QF contracts, and regulatory programs, such as decommissioning costs, DSM costs, certain tax liabilities, and operating costs. SDG&E assumed that ratepayers would pay SDG&E the book value of its generating assets and that those assets would be turned over to an SDG&E affiliate, who would sell power to SDG&E at an unspecified rate. PG&E and Edison included certain future operating costs in their CTC estimates. In calculating the present values of these costs, the utilities used various discount rates. They emphasized that actual uneconomic assets and obligations will depend on the market price for electricity over time. If market prices are high, uneconomic assets will be low; if market prices are low, uneconomic assets will be high. In addition to calculating uneconomic assets under current revenue requirement assumptions, all three utilities presented estimates of uneconomic costs assuming the adoption of recent settlements regarding cost recovery of nuclear facilities. For PG&E, uneconomic cost estimates fall substantially when the modified Diablo settlement is presumed to have been adopted by the Commission, as illustrated in Table 1. Several parties, including DRA, CEERT, and CLECA comment that the calculation of uneconomic assets does not appropriately include operating costs that are not "sunk." These parties argue that future operating costs can be reduced or avoided. If the plants are sold, operating costs would be someone else's responsibility. If the plants are not sold, the utilities would have an opportunity to recover those expenses in a competitive environment. DRA argues the utilities assume market prices that are too high and load factors that are too low. When corresponding adjustments are made, using utility data in other proceedings, uneconomic costs fall dramatically, according to DRA. Several parties also object to the utilities' inclusion of a rate of return in the estimates of uneconomic assets, arguing that the utilities should not be able to earn a return on plant costs for which the utilities face no risk. Parties also disagree on the allocation of risk for uneconomic assets between shareholders and ratepayers. The allocation of risk is reflected generally in ratemaking approaches proposed by the parties. The utilities propose that their uneconomic assets be regularly evaluated based on the previous period's market prices and fully recovered on a dollar-for-dollar basis. They propose to enter the amounts in a balancing account and to recover or refund over- and A3.35 ATTACHMENT 3 ATTACHMENT 3 undercollections in subsequent periods. Shareholders would not take any risk for uneconomic assets on the grounds that the utilities' investments were made as part of their historic obligation to serve the public. Under their proposed recovery method, the utilities would continue to earn a rate of return, although the rate would be discounted. Edison also proposed that the Commission establish a CTC for transmission costs in the event those costs are not competitive. No nonutility parties who presented testimony supported the utility proposals. Most were critical of them on the basis that they would provide no incentive for the utilities to become more efficient because the utilities would take no risk for recovering their uneconomic assets as they do now. Many also expressed concern that guaranteed recovery mechanisms, such as those proposed by the utilities, would be anti-competitive because the utilities would always be able to sell electricity at a market price without any risk. Some parties suggest that the utilities should divest their generating assets to avoid any ongoing conflicts of interest and as the most accurate way to determine the market value of utility assets. National Power proposed a specific set of policies for auctioning off utility generating assets under which the utility would have right of first refusal at the highest bid. CEERT proposes that the utilities' transmission assets be sold. According to CEERT's estimates, the profits made on the sale would offset the uneconomic costs associated with generating assets. Most parties, including the utilities, proposed that the CTC be paid by consumers as part of transmission or distribution bills and commented that FERC approval will be required to effect any change to transmission rates. PG&E urges the Commission to "unbundle" the CTC and include it as a separate line item on customer bills. Edison and SDG&E propose that customers of communities that establish municipal utilities continue to pay a share of the CTC by way of an "exit fee" or surcharge. In deriving the CTC rate for each customer class, all of the utilities used the Commission's existing cost allocation methodology (referred to as "equal percent marginal cost" or "EPMC"), consistent with the policy statements made in the Rulemaking. The utilities suggest, however, that this cost allocation methodology may require changing as circumstances change. (End of Attachment 3) A3.36