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1994 Electricity Report

California Energy Commission

Publication Number: P300-95-002
November 1995

Internet Version Contents

Introduction and Executive Summary
Chapter 1: The Challenge Of A Competitive Electricity Market

Copies of the final version of this document can be ordered
from the Energy Commission's Publications Unit.

Introduction and Executive Summary

The electricity industry in California is about to undergo its most radical changes in the last 50 years. For decades, most of California's electricity needs have been provided by large, vertically-integrated utilities that provided everything necessary -- from generation, transmission and system coordination to distribution, hook-ups and billing -- to ensure that consumers would have electrical power whenever they needed it. Because these services were regarded as monopolies, they were closely regulated by the state and by local boards which set reliability standards and service conditions and the rates for the entire bundle of electricity services. Within five years, and probably less, major elements of this industry will be transformed by the forces of competition. There will be new market institutions, new kinds of utilities, new market actors performing generation, coordination and merchant functions and new regulatory guidelines designed to foster and complement market forces, ensuring that markets function fairly.

The current electricity industry relies on utilities and their regulators to make virtually all of the important decisions about how the electricity system is structured, operated and paid for. Today, utilities and regulators decide how many power plants will be built, who may build them, which technologies to use and how much consumers must pay for them. They decide what services consumers receive, how they are delivered and how much customers are billed. Much of this will change. A competitive electricity industry may keep a few of these features, but more likely it will transfer the responsibility for making most of these decisions to consumers. In a competitive industry, consumers will have greater control over the services they receive and the prices they pay. They will be allowed to choose which suppliers will provide the services they want, and perhaps, which technologies their suppliers will use. Once they are empowered to exercise these choices the range of choices available and their value to consumers will expand.

The fundamental reason for fostering a restructured electricity system is that markets with competing suppliers and little regulation generally do better at creating economic benefits than do heavily regulated monopolies. The forces of supply and demand do a better job of providing needed goods and services at a reasonable price than do the decisions of government regulators. Economists call this "economic efficiency." Economic efficiency is a measure of the total value to society of a good or service; it takes into account both the worth to society and the price it pays. The Energy Commission believes that electricity industry restructuring has substantial potential to increase the economic efficiency of the electricity market and thereby make the state as a whole better off; in the long run, most consumers should get more value and pay less for it than they would under the current system of monopoly regulation. Thus, while many topics and issues are discussed in this Electricity Report, all have this common theme: reformulating the electricity industry in California to create greater economic efficiency.

When the electricity industry was in its infancy, its physical and economic characteristics indicated that electricity was one of the rare commodities that could be better provided by a monopoly. The primary justifications were that it made little sense to have duplicate facilities, such as transmission lines of different companies running down both sides of the street; that the unique needs of electricity system coordination and economies of scope made vertical integration of generation, transmission and distribution functions appropriate; and that only single firms could realize substantial economies of scale. Once government, however, allowed monopolies exclusive rights in various geographic areas, it also had a responsibility to regulate the companies so that they could not use that monopoly power to charge unfair prices; in turn, price regulation required government to provide utilities with a steady stream of income because the utilities could not act like free market participants, changing their goods and services or modifying their prices in order to maintain profits. Thus, government regulation has substituted for competition in order to keep prices at a reasonable level and to provide investors with profits commensurate with the risks they take. But it has always been recognized that regulation is a second-best solution and that market forces are better at keeping prices down and in providing needed goods and services than is government regulation of monopolies.

The justifications for monopolies in the electricity industry, at least in the provision of generation and many customer-level services, are for the most part no longer applicable today. More than a decade of experience with independent, non-utility generators has convinced most observers that neither economies of scale and the extensive capital requirements of power plant construction nor economies of scope from vertical integration require that monopoly utilities remain the sole providers of electric power. As the argument for monopoly ownership and control over generation has eroded, so has the rationale for monopoly regulation over the generation sector of the industry. Traditional cost-of-service, rate-of-return regulation and the corresponding protection of exclusive utility franchises are becoming increasingly difficult to justify when the essential product of the industry can be produced efficiently by competing suppliers.

Powerful forces are now the catalysts for competitive changes. The Energy Policy Act of 1992 (EPAct) (Public Law 102-486) spurred greater wholesale competition by creating a new category of non-utility wholesale generators. EPAct also required all transmission-owning utilities to grant non-discriminatory access to the transmission grid, empowering the Federal Energy Regulatory Commission (FERC) to order utilities to provide such access. FERC responded by first requiring utilities, on a case-by-case basis, to grant access to third party wholesalers on terms and conditions comparable to those the utility provides for its own wholesale transactions.

More recently, FERC has proposed industry-wide rules that would require all transmission-owning utilities to file open access tariffs that provide comparable access to the grid and ancillary services, while requiring the utilities to make all of the information necessary for wholesale trades available to third parties in the same way and at the same time that the utility itself receives such information. Even as those rules are being considered, an increasing number of wholesale transactions are occurring among utilities, independent power producers and wholesale marketers. Once adopted, these rules will go a substantial way to placing utilities and third parties on an equal footing in competing for the wholesale market.

The major remaining barrier to realizing a competitive generation market is the absence of a market institution that will ensure all generators have equal and open access to the customer base on which the electricity market depends. Parties in California are already taking the initial steps necessary to create that institution and to define its rules. In short, the long era in which utilities were the exclusive traders of wholesale power is over; once an appropriate institution is in place, the era in which utilities are the exclusive suppliers to retail customers will end as well.

Additional pressure for change in California has come partly from the dissatisfaction of certain customer groups with the high rates charged by California's investor-owned utilities (IOUs) and some municipal utilities. The state's IOUs have some of the highest electricity rates in the nation, though the significance of this statistic is not altogether clear since the average bills that residential customers pay have been well below the average bills for electricity customers nationally.

Figures 1 and 2 (below) illustrate how California system average rates and residential electric bills compare, respectively, with the national average from 1970 through 1993. Higher rates and lower bills are somewhat interconnected; for example, for more than a decade, and under policies endorsed by legislators and governors of both political parties, California has implemented tough energy conservation standards for new buildings and appliances and California's utilities have pursued energy efficiency programs more aggressively than their national counterparts. The utility programs have increased rates somewhat, but they, along with state standards, have also lowered customer bills by reducing end-use consumption in all customer classes. In effect, Californians have paid for lower bills partly with higher rates; as residents have lowered their consumption by becoming more efficient, there are fewer electricity sales over which to spread the fixed costs of the electricity system.


Comparison of California and U.S. System Average Rates
1970 to 2013

Sources: 1970-1992 EIA; 1993 EEI.


Comparison of California and U.S. System
Average Annual Residential Electricity Bills
1970 to 1993

Sources: 1970-1992 EIA; 1993 EEI.

Even in the absence of industry restructuring, California's rate picture should improve over the next decade. Commission forecasts for the major utilities, summarized in Figure 3, show average rates declining in real terms, mainly as a result of reduced prices paid to qualifying facilities (QFs), lower natural gas prices and reduced depreciation expenses for nuclear plants.


Califoria System Average Rates by
Customer Class and State-Wide Total
1970 to 2013

Sources: 1970-1993: EIA and EEI; 1994-2013: ER94 Electricity Price Forecast, May 1994.

Nevertheless, electricity rates are an important element in business decisions for many firms, both large and small. California's industrial, commercial and agricultural electricity customers confront stiff competition from firms in other states and nations. The importance of gaining control over electricity rates, as well as any other cost of production, is not a philosophical question; to many firms it is a matter of economic survival.

Yet the connection between the desire to introduce greater competition and the pressure to lower electricity rates quickly is somewhat tenuous as the factors that have produced high rates for California's IOUs are varied. It is not safe to assume that changes promoting competitive markets will deal immediately with all the causes of today's high rates. The California Public Utilities Commission (CPUC) examined some of those causes in its "Yellow Book" (California's Electric Services Industry: Perspectives on the Past, Strategies for the Future; CPUC Division of Strategic Planning; February 3, 1993) and concluded that the current complex, inefficient regulatory system is itself partly to blame.

The Yellow Book also acknowledged that a large part of the high rates charged by the IOUs is the result of key investment decisions made a decade or more ago, more or less jointly by both utilities and state regulators. California regulators and utilities, like those in many other states, chose to pursue large nuclear plants in the 1970s. Like many others across the country, nuclear plants turned out to be far more expensive than their advocates hoped or even their critics feared. In addition, in reaction to the oil crises of the 1970s, California aggressively pursued alternative energy technologies and sought to make those alternatives competitive with the traditional choices of oil, coal or nuclear power. For 15 years, the state sought to accelerate the introduction of cogeneration and renewable power plants into the utilities' resource mix. Those policies produced a viable alternative energy industry in California with many beneficial effects. There is no doubt that, along with substantially lower electricity demand induced by state energy efficiency policies, alternative energy sources forestalled the need for more traditional resources. But the state imposed long-run, fixed-price contracts on the utilities for too much of the alternative generation and at prices pegged to fuel-price forecasts that, in hindsight, were too high. Those investment and regulatory decisions are major reasons why California's IOU rates are nearly 40 percent higher than the national average.

Admitting these past mistakes creates a dilemma for advocates of change. Much of the pressure for industry and regulatory change may by driven by a desire to lower quickly -- or even escape -- today's high rates, but the changes that are realistically achievable from more competition cannot provide substantial near-term rate relief for all customers at the same time. Realistic changes cannot reverse the past decisions that caused those rates. Someone has to pay. One principal mechanism proposed so far to provide such immediate relief is to absolve ratepayers from some or even all of the responsibility for paying for past decisions, thus shifting the cost responsibility of uneconomic power plants to utility shareholders and creditors. Shareholders and creditors regard this suggestion as an unfair breach of a "regulatory compact" between customers, regulators, utilities and their investors. From some consumers' point of view, an even worse alternative is that the uneconomic costs should be shifted from those who are complaining to those who lack the resources for effective advocacy. The argument that California should move towards a competitive electricity market in order to substantially reduce average electricity rates quickly is, therefore, suspect; either it is tainted by the implicit approval of shifting inappropriate costs to someone else or it is disconnected from near-term realities. And yet, the solutions offered by competition have a strong claim for legitimacy in the long run.

In fact, the long-run arguments are compelling. A more competitive market might well preclude investors, utilities and regulators from making the same kinds of investment mistakes that contributed to today's high rates; indeed, in a competitive market the key decisions might not be made by utilities or regulators at all. While private investment markets will not be immune from their own faulty price forecasts or misjudging competitive options and market trends, those markets will be more likely to absorb and disperse the risks and not pass them through to consumers.

Moreover, experience with industry restructuring in other countries indicates that significant efficiency gains are achievable from competitive generation markets. In the United Kingdom and elsewhere, generation competition has forced producers to cut costs well below the levels previously experienced by regulated monopolies. The same effects can be expected here; California utilities are already responding to the threat of increased competition by cutting costs in a variety of ways. Over the long-run, competition should make producers more efficient and put downward pressure on electricity prices, provided that competition is fair and efficient and not dominated by producers or marketers with undue market power.

This Electricity Report is, therefore, premised on the belief that the emergence of a competitive electricity market is not only inevitable but desirable. Besides the likelihood that competitive generation markets will make producers more efficient and the potential that privatizing investment risks will minimize the kinds of mistakes that contributed so much to today's high rates, the Energy Commission sees other major benefits from electric industry restructuring.

Perhaps the most important benefit is the potential to liberate customer choice from the narrow decisions imposed by monopoly utilities and their regulators. To achieve this, new market-oriented structures are needed to allow customers to have, understand and exercise choices, and to begin to demand new services more closely tailored to their individual needs. Electricity can be viewed as a single commodity or as a wide range of possible services, services that can be combined in innovative ways with energy efficiency and management devices, telecommunications and other services valuable to consumers. As new suppliers enter the market and competition spurs new technologies, new kinds of services and products should emerge from the electricity market, just as they have in the deregulated telecommunications industry.

Another important benefit from industry restructuring can arise from moving towards more efficient pricing for electricity-related services. Today's electricity rates typically bundle in a single rate the costs of generation, transmission, distribution, system coordination, billing and other services currently provided by vertically integrated monopolies. Moreover, pricing tends to be uniform throughout an entire utility service area and over time; differences in the costs of serving different areas and in the production cost between one period and another are typically ignored for most customers. Given this rate uniformity, prices do not effectively signal the true costs of service, nor are prices for any one component of service, such as generation, readily observable by consumers or other users of the system.

Transparent, cost-sensitive prices can give market participants clearer signals about the relative value of consuming or producing more or less at various times, about the value of different services or different levels of service, about the tradeoff between generation and transmission, and about the merits of locating new facilities or loads in one location versus another. Without such signals, consumption and investment decisions are less efficient, and inefficient investment decisions skew the resource mix, the development of technologies and the choice of service options. In a competitive market with efficient pricing, it should be possible for customers to make more effective decisions about when and how much to use electricity services, for various technologies to compete effectively in the right market niche and for new technologies to emerge without the need for inappropriate subsidies.

An open competitive market with efficient pricing signals should also eliminate the need for one of the most difficult aspects of utility regulation: the requirement to regulate the cost of, need for and choice of new utility power plants. Since 1975, the Energy Commission has been required by state law to provide a public process, based on independent forecasts and analyses, for siting proposed thermal power plants over 50 megawatts in capacity. For the past six years, the California Public Utilities Commission (CPUC) has engaged in a controversial proceeding known as the Biennial Resource Plan Update (BRPU) to determine each IOU's need for resources, the potential costs of those resources and the rules under which each utility would be compelled to acquire power from independent power producers to meet some portion of those needs. In a competitive market, the rationale for this well-intentioned but difficult, highly contested and, so far, still unsuccessful effort, could be completely eliminated. But its elimination depends on the creation of a fair and efficient competitive market in which all potential suppliers -- utility and non-utility alike -- have open, non-discriminatory access to the transmission facilities and ancillary services essential to conducting operations and, equally important, open access to the consumer market. Equally crucial, consumers must have open access to all potential suppliers. No such market exists in the United States. The 1994 Electricity Report points the way to the creation of a competitive market.

(Note for Internet Version: Most of the chapters mentioned in the following paragraphs are not contained in the Internet version of the 1994 Electricity Report. Please order a copy of the final printed version from the Publications Unit.)

In Chapter 1(below), the requirements for a competitive market in generation and transmission are examined, focusing on the institutions needed to create or foster a fair, open and efficient market.

Much of the California and national discussion stimulated by the CPUC's April 20, 1994, proposal (Proposed Policy Statement on Restructuring California's Electric Services Industry and Reforming Regulatory Policy; CPUC, R.94-04-31 and I.94-04-032; April 20, 1994) to allow customers direct access to competing suppliers has been a debate about the structure of the model for a competitive wholesale market. The debate is examined in some detail and a set of principles is proposed that lead to a solution. That solution, recommended by the Energy Commission and other key parties and endorsed in principle by the CPUC, includes a pool-based spot market coordinated by an unbiased, independent system operator, coupled with direct customer access to suppliers. A system operator is essential for coordinating the interconnected transmission network, facilitating an efficient market and providing all generators open, comparable access to the transmission network and to those ancillary services essential for market trades. Equally important, the solution allows generators and marketers direct commercial access to retail consumers, thus liberating customer choice.

Liberating consumer choice in generation supplies is only half the task. To allow consumer choice to realize the benefits of individually tailored services, it is necessary to pull apart the current bundle of utility-provided services, separating those that can be provided by competition from those that must remain the responsibility of regulated monopolies. Chapter 2 examines the various types of electricity-related services and suggests those that may be appropriate for unbundling.

The creation of a competitive wholesale and retail electricity market is not without significant risks and uncertainties. Foremost among these is the possibility -- already confirmed in some areas -- that important public services and benefits now provided by the electric utilities may languish during the transition to competition. Those benefits may not be secured as effectively by the utilities or replacement institutions unless appropriate actions are taken. For the past 20 years, California has increasingly called upon the utilities to provide a wide range of such public benefits, including energy efficiency programs; research, development and demonstration of new supply and efficiency technologies; promotion of cleaner transportation systems; improved air quality and enhanced electric system reliability through resource diversity.

In a competitive regime, two things will happen. First, utilities will be under increasing pressure to cut costs and lower rates to remain competitive with other suppliers who do not have the same public responsibilities. This effect is already happening as Investor-Owned Utilities (IOUs) drastically cut their proposed funding of energy efficiency, research and development, and other programs. Second, part of the competitive market will focus on the efficiency of producing and selling electricity as a commodity, rather than a bundle of related services associated with lighting, heating, air conditioning and mechanical processing. For some advocates of public policy benefits, a market focused on a single commodity and its pricing seems incompatible with the notion that utilities have the main public responsibility to provide a wide range of energy efficiency services.

There is, however, no reason why an expanded range of energy services and public benefits cannot be provided by utilities and by other market actors and non-market institutions, even as the production and pricing of the commodity electricity is made fully competitive. The key is to provide a structure in which the production and sale of electricity is free to respond to and be disciplined by competitive market prices while providing alternative ways of funding and implementing public policy programs that, while perhaps tied to other elements of a service rate, are not tied to the price of electricity production and do not depend on whether the producer is a utility or another supplier. Chapter 3 examines how the role of utilities in providing public benefits may change under competition and how other actors armed with comparable information and reacting to efficient prices may also provide some of the important public benefits. In addition, the need for new funding mechanisms to complement competitive markets and to provide those public benefits that may not be available from market solutions is discussed.

The advent of a competitive market presents unique and challenging problems for California's publicly-owned utilities. Chapter 4 of this Electricity Report discusses several aspects of the municipal utility response to competition.

When a competitive electricity market begins to function, the need for governmental regulation and oversight will also change. On the whole there should be less government activity, but in some areas, such as providing information to market participants and guarding against abuses of market power, government's role may expand. Chapter 5 discusses the ways in which the Energy Commission and other governmental responsibilities are likely to change.

Chapters 6, 7 and 8 describe the technical analyses upon which much of this Electricity Report is based, and set forth the Energy Commission's assessments of electricity supply and demand trends. Chapter 6 contains forecasts of future electricity demand in California. Chapters 7 and 8 describe the state's current and potential future options for electricity supplies, both in generation and in energy efficiency.

Chapter 9 presents the Energy Commission's integrated assessment of need, which describes the new electricity options that can provide economic benefits for California. Finally, Chapter 10 describes the criteria that the Energy Commission will use during the next two years to determine whether proposed new power plants are "needed." In recent years, "need criteria" have focused on protecting utility ratepayers from unjustified financial risks and burdens of power plant construction. In recognition of the fact that in a competitive market entrepreneurs will shoulder the risks of new power plants, Chapter 10 proposes a major departure from past criteria: basically, any plant that proposes to operate competitively, without looking to ratepayers to provide a financial backstop, will be found needed.

Table Showing 1994 Dependable Capacity of Electricity Generation
(Table 7-1 from the 1994 Electricity Report, Chapter 7)

Chapter 1

The Challenge Of A Competitive Electricity Market

Creating a competitive market for electricity presents challenges that are both difficult and unique. The industry is starting from a position in which vertically integrated utilities function as regulated monopolies; they have almost exclusive franchises to provide electricity to end-use consumers within their own service areas. Rates for electricity service are set mostly by regulators, not by market forces. Choices about which generators will be built and operated and which services will be provided are made by utilities and their regulators, not driven by the choices of consumers. In moving towards a competitive electricity market, portions of the industry that must remain monopolies will have to be distinguished and remain subject to regulation, while the continuing need for central coordination of the transmission network will have to be recognized and preserved. But the remainder of the industry and its traditional regulatory protection will have to be carefully and systematically pulled apart and replaced by mechanisms responsive to consumer choices and market prices. To make this transition successfully, we will need to know what a competitive electricity market driven by consumer choice might look like, as well as understand the unique aspects of electricity that require continued central coordination.

This chapter discusses the elements of a competitive electricity market in generation and related transmission services. The following chapter will focus on providing choice in retail services for consumers.


Competitive markets are driven by the choices made by consumers. The needs and desires of consumers help define the products and services suppliers offer, how they are packaged and how they are delivered. Market rules must, therefore, be flexible, allowing suppliers and consumers to contract with each other in a wide variety of ways designed to match the precise needs of both buyer and seller. Market participants must be free to tailor precise individual trades in ways that provide the most value to the customer and allow for maximum efficiency for the supplier. When all these elements are present, competitive markets should lead to results that are economically efficient.

Competitive markets include both a physical and a commercial component. The physical component is the ability of products and services to be physically delivered from suppliers to consumers. In the electricity sector, most of the physical delivery network already exists; it consists of the direct connection every utility customer already has through the wires of the distribution and transmission network to the suppliers of generation. In that sense, all consumers already have "physical direct access" to the market. What is needed to make the existing physical access meaningful are the rules that will ensure that every potential supplier -- utility and non-utility alike -- has open and non-discriminatory access, on the same terms as every other supplier, to the physical network that already connects suppliers to customers. The necessary rules do not yet exist.

The commercial component of competitive markets consists of the ability of suppliers and consumers to make and implement commercial trades under whatever terms and conditions the parties choose. Buyers and sellers need to be free to enter and exit the market when they desire to do so. The price signals for making such decisions must be both efficient and transparent, allowing market participants to make intelligent and timely choices about whether and when to produce more or less, consume more or less or switch to alternative suppliers or customers. Part of this component exists today in the ability of competing suppliers to engage in wholesale trades with utilities. But the ability to sell is relevant only if the utilities will be "willing buyers", which has not always been the case. Moreover, traders who do not own transmission may not always gain access to the transmission and distribution network necessary to implement their trades. If access is granted, it may not be granted on terms that are comparable to those the transmission owner assumes for its own transactions. The lack of comparable access frustrates some wholesale trades making competition less likely and less efficient. [1]

At the retail level, commercial trades are even more restricted. What is missing is the ability of suppliers to have direct commercial access to retail consumers -- the essential foundation of an electricity market based on consumer choice -- and the reciprocal ability of consumers to exercise choice through direct access to competing suppliers. Today, direct commercial access is blocked by statutes, regulations and the tradition of granting monopoly utilities almost exclusive franchises for serving retail customers.

Given these commercial and physical requirements, two distinct but complementary elements are necessary for both consumers and suppliers to allow a competitive electricity market to emerge. First, suppliers and consumers need the commercial freedom to contract with each other under terms and prices they mutually accept. With an open contract market, suppliers can respond to consumer choices, and suppliers and consumers can agree to lock in prices and other terms ensuring, for whatever period they select, any degree of certainty about prices and services that they want.

The second element is equally important. Suppliers and consumers need a mechanism to ensure the physical delivery of the electricity being traded, along with the ability to turn to a "spot" market to buy or sell additional electricity not otherwise covered by a contract. The ability to turn to a spot market is essential to implementing contracts, because it ensures that physical delivery under any contract can occur irrespective of whether any contract supplier's output perfectly matches, at any given moment, the precise consumption of a contract consumer. Because consumers' demands and suppliers' generation can change frequently, either by design or by accident (e.g. by mechanical breakdown), physical mismatches between consumers and suppliers are inevitable. Without an efficient spot market to make up for these mismatches, contracting parties would frequently confront the legal and commercial risks associated with a failure of either party to perform as expected.

The presence of a spot physical market is especially critical in an electricity market, because the physics of electricity and the interconnected nature of the existing transmission network require that the amount of electricity put onto the network by suppliers constantly and swiftly match, except for line losses, the amount of electricity taken off the network by consumers. Regardless of the actions of contracting parties or the degree of importance they place on maintaining their own matching balances, an overall system coordinator must ensure some balancing between aggregate loads and generation at all times to maintain system reliability, stability and safety. Hence, the electrical need for central coordination and the commercial need for a spot physical market are inextricably linked. Even if the system coordination and spot market functions were performed by separate entities, the functions will have to be closely coordinated until new communication and control technologies are developed, making any separation mostly meaningless.

A competitive electricity market thus requires both a spot physical market, with its associated system coordination and balancing functions, and a longer-run commercial or contract market with its focus on bilateral trades between buyers and sellers. Together, both allow and are necessary for consumer choice to be exercised efficiently. Unfortunately, most of the California and national debates about models for a restructured electricity industry have become mired in a false debate about whether to create a spot physical market through an institution called a "pool", or whether instead to create a commercial contract market solely through the mechanism of bilateral contracts. Spot markets and contract markets serve different, albeit complementary, purposes; neither is sufficient and both are necessary. The debate has also been mischaracterized as a choice between a wholesale or a retail market, with some parties mistakenly characterizing pools as allowing only wholesale competition and others defining bilateral contracts as focused on retail competition. Yet a pool can provide critical spot market transactions essential for both wholesale and retail markets thus facilitating bilateral contracts with either wholesale entities or retail consumers.

The all-too-common assumption that spot market pools and bilateral contracts represent alternative models, and even mutually exclusive alternatives, needs to be discarded. Neither spot market pools nor bilateral contracts should be emphasized to the exclusion of the other. An efficient spot market for assuring short-run physical delivery and system balancing and an efficient contract market for assuring long-run commercial and pricing certainty are complementary and necessary components of a competitive electricity market. To create that market, advocates and regulators should embrace both equally.


Transmission is a Network

The electricity transmission system that serves California is a highly complex network that interconnects the entire western United States and neighboring parts of Canada and Mexico. The network provides multiple, alternative connections between generating plants, substations and load centers, as well as multiple interconnections with other control areas, utilities and regions. The western regional network is more extensive and varied than the networks in other countries that have undergone electric restructuring. In several of these countries -- Norway, Chile, Argentina, Australia, New Zealand -- much of the transmission system is mostly radial, lacking the multiple loops that allow and complicate network interactions in California.

Within the complex regional network in the western United States, electricity is free to follow alternative paths, each path offering varying degrees of resistance. Each path's transfer capability can change as generators put more or less electricity onto the network and consumers take more or less electricity off the network. When electron "flows" are induced by a power plant's generation on any point on the network or by significant changes in demand, they affect the flows everywhere else, reducing or increasing the magnitude of flows elsewhere, or even changing their direction. As a result, a single generator's power input to the network can require utilities elsewhere on the network to curtail or increase the generation at other plants. Further, network flows are essentially instantaneous, while storing electricity is difficult with today's technology. Inputs and outputs on the network must, therefore, quickly balance at all times. These realities, imposed by the physical structure of the transmission network and the physical laws affecting electricity, mean that the power flows on the transmission network require continuous central coordination. This is a monopoly function.

Understanding and accounting for these physical realities and the resulting need for central network coordination are fundamental to the debate about how to achieve a competitive electricity market. While the textbook view of competitive markets in general is that economic efficiency can occur through completely uncoordinated, decentralized trades, the reality of the electricity system is that at least some central coordination of the flows on the transmission network is necessary to keep the system operating within acceptable limits, to maintain proper voltage and constant frequency, and to keep generation and loads in balance. Finding the appropriate balance between the need for central coordination and the market paradigm of unregulated, decentralized trades remains a most challenging aspect of electric industry restructuring.

Pricing Transmission in a Network

The challenge is made more difficult by the need for efficient pricing of the transmission component of an electricity system. In most other industries, the transportation component is clearly distinct from the production component, making it much easier to comprehend and simpler to isolate for purposes of ascertaining its costs and resulting prices. "Unbundling" transportation from production in these cases is simple, since it occurs sequentially: a good is produced, then it is transported to a market and then it is purchased. In the electricity system, generation, transmission and consumption must occur more or less simultaneously. Moreover, in most other industries the transportation component is itself a competitive function. This is not true in electricity; because of the need for centralized control, transmission needs to remain a monopoly.

The monopoly characteristics of transmission, including the need for centralized coordination of network interactions, at first seem to preclude market-based pricing for transmission in the ordinary sense. At the same time, network interactions between generation, consumption and transmission frustrate efforts to "unbundle" a separate transmission service and to price it separately.

Even today, when network effects and the unique physical characteristics of electricity are more clearly understood by utilities and their regulators, many still discuss transmission pricing as though electrons will flow along a path determined by contracts -- a "contract path" -- evoking analogies to how transportation functions in other industries. But electrons do not read contracts; they follow physical laws of their own. Yet the contract path fiction continues to lead to efforts to price transmission along designated paths, adding up separate, unbundled transmission prices for each transmission link, and to define physical contract rights along the designated contract paths.

Over the past decade, state and federal regulators have tried to open the wholesale generation market to more competition. Those efforts have repeatedly stumbled on the problem of providing competitive generators access to the transmission network, a problem which has been defined partly in terms of overcoming the control exercised by transmission owners, most of them vertically integrated monopolies. Federal statutes that require owners to grant third parties "open access" to the network are designed to solve this conflict between ownership and control. But physical control by self-interested owners is only half the problem. The other half is pricing; how do you determine the appropriate price to charge those who wish to use the transmission network, given the unreality of contract path imagery? Whether markets or regulators determine the price, the complexity of this question is magnified by network interactions.

When generation and loads change in one region they can affect network flows in another region. As network interactions occur, the transmission capability between various points changes, but not in an easily predictable way. The effects can reduce or increase any utility's ability to transfer power from one region to another. Whenever this happens, utilities must adjust generation at various locations to make up for lost (or gained) transfer capability and to stay within operating limits across the network. These adjustments impose costs (or savings) on each affected utility. Network interactions created by generation changes can thus shift costs to other network users. These cost shifts make efforts to price transmission fairly and efficiently problematic. Yet fair, efficient pricing must be achieved if a truly efficient electricity market is to be achieved.

As interconnections between utility service areas have increased over the last decade, network interactions have increased accordingly, forcing utilities to design ways to limit them or compensate for their effects. Within a utility's own service area, the purely localized cost effects of network interactions can be aggregated across the service area and simply rolled into a bundled rate. This bundled rate can then be charged to all ratepayers without attempting to account for differences between sub-regions within the same service area. Network interactions across utilities, however, require efforts either to control them (to avoid cost shifts between utilities) or to compensate for them in some fashion. Regional cooperation among utilities has, therefore, become necessary to avoid significant cost shifts and to implement fair rules for compensation.

The Challenge of Network Pricing in a Competitive Market

The emergence of a more competitive generation market means that more and more generators are seeking access to the network. Today, the number of competitors is growing and the number of power transactions is expanding, producing a corresponding increase in network interactions and compounding the difficulty of accounting and compensating for resulting cost shifts. Yet the number of entities controlling generation output is limited. In a fully competitive generation market, there could be many more generators and market participants controlling generation trying to match discrete generation supplies with discrete customer loads. This might cause dramatic increases in demands on the transmission network and its coordinators.

Expanding competition is thus in tension with the need for cooperative efforts to coordinate for network effects and fairly compensate for them. In today's world, containing network interactions has been accomplished simply by allowing fewer trades, but that result is not acceptable as market participants will demand the ability to make trades. In the past, informal working arrangements between neighboring utilities might have been sufficient, but today and in the future more formalized rules affecting not just utilities but all network users will be necessary to ensure that competitors who cause network effects fairly compensate (or collect from) those competitors who are adversely or beneficially affected.

The Need to Define Network Rights

As the number and complexity of commercial power transactions grow, it will become essential to define "transmission rights" clearly. This will not be easy since network interactions limit any notion of a readily ascertainable, let alone constant, transfer capability between any two points on the network. Concepts like "firm capacity", traditionally used by utility planners and power marketers, have always been somewhat misleading, implying a physical guarantee of a readily determined and constant portion of a given transmission link. To be useful in a commercial market, transmission rights will need to be redefined as "network rights". The nature of the right will focus not on the idea of physical guarantees to discrete transmission links but rather on the important commercial rights to compensation whenever congestion on the network forces generation and costs to shift from one region to another, and from one competitor to another.

As the competitive market expands -- and the numbers of participants, trades and network interactions grow -- the transmission system may have to expand in different ways to meet the commercial needs of market participants. The size and configuration of today's network is largely a function of the separate planning efforts of individual utilities, each attempting to deal primarily with the needs of its own native customers and connecting its own generation to load centers. In the last twenty years, interconnections between different service areas have been constructed both to enhance inter-regional reliability and to facilitate beneficial trades involving utilities and federal power marketers. For the future competitive market, the challenge will be to devise an approach to network pricing that not only accounts for network interactions and compensates traders fairly through appropriately defined network rights, but also provides clear and efficient incentives regarding the need for, timing, size and location of network expansions and generation investments.

Network interactions, the need for central coordination and the potential for cost shifts make the challenge of an electricity market both difficult and unique. If California is to move responsibly towards an efficient and competitive electricity market, those challenges must be recognized and met.

In the next section, we will describe a model -- the California Market Model -- for a restructured electricity industry. The model is designed to meet the challenges of a competitive electricity market while providing to the greatest practical extent for the decentralized trading and consumer choice that characterize true competition. The California Market Model includes both a mechanism to ensure a spot physical market and the ability of traders to engage in bilateral commercial trades at both the wholesale and retail levels. And it meets the challenge of efficient network pricing.


The Foundation Principle:
Economic Efficiency Through Consumer Choice

The California Market Model is a competitive electricity market founded on the principle of pursuing economic efficiency by liberating consumer choice. The model is designed to allow market participants to respond to the needs and wishes of consumers and to allow consumers to choose, within the technical limits of the electricity system, the electricity services they want from any supplier they choose, under prices and terms they freely accept. Within that framework, consumers may also choose "not to choose". The California Market Model is designed to ensure that benefits of a competitive generation market -- including lower electricity prices -- are available to consumers even if they choose to do nothing other than continue receiving electricity from the local distribution utility that now serves them. At the same time, the model recognizes the need for a degree of central coordination to maintain system reliability, stability, and safety, along with the associated need for a spot physical market to ensure moment-to-moment physical delivery and to support commercial contracts.

Features of the California Market Model

There are four basic parts of the California Market Model. The first is a competitive generation market in which multiple suppliers, perhaps including plants owned by current utilities and government entities as well as independent power producers, would compete on the basis of price and other terms to provide power. The second part of the model is an independent system operator, or ISO, that would (1) control the transmission network and ensure fair access to it for all generators, (2) take the actions necessary to keep supply and demand in balance continuously, and (3) provide a spot market for power. We discuss the ISO in some detail below. The third part of the model is the distribution utility. The distribution function, which we expect would continue to be performed by the state's current utilities as regulated monopolies, would provide and maintain the local wires for the final delivery of power to consumers. The fourth part of the model is the consumers themselves, who would now be able to choose their own service suppliers, whether aggregators, customer service intermediaries or generators, via direct access.

In the California Market Model, all consumers would be free to exercise choice through direct access to multiple suppliers in a competitive market. Individual consumers, or groups of consumers choosing to aggregate their demands, could contract directly with alternative suppliers, establishing whatever commercial terms and conditions they choose, locking in prices, services and other terms for whatever period suited them. Aggregation could occur in many ways including between consumers in different locations as well as across entire communities.

Consumers and suppliers would be free to arrange any type of commercial transaction they determined to be in their economic interest. Responding to individual consumer needs, suppliers would be free to tailor the electricity services they offered and to package electric deliveries with any other services -- price and service metering, energy efficiency measures, telecommunications -- valuable to the consumer. Consumers would also be free to tailor their needs to meet the operational or efficiency needs of suppliers, thus maximizing and sharing the resulting benefits. In each instance transaction costs would be reduced ensuring that the benefits of market efficiencies are realized.

To implement these commercial arrangements, all market participants would have access to the transmission and distribution network. To ensure that access were provided on comparable, non-discriminatory terms, the network coordination functions now performed by the utilities would be handed over to an ISO. Participating transmission-owning utilities would turn over to the ISO full operational control of all of their transmission facilities. The ISO would be a new, unbiased entity, neither owned nor controlled by any utility or market participant; it would be a separate, monopoly entity subject to regulation. Because the ISO would be operating the transmission network and assuring open comparable access to the network and ancillary services, the ISO would be regulated by the Federal Energy Regulatory Commission (FERC). The ISO would be responsible for coordinating the network and maintaining system reliability, stability and safety. To perform these functions, the ISO would offer on a non-discriminatory basis all ancillary services necessary to accommodate commercial trades between market participants within the operating limits of the transmission network.

Among the ancillary services offered by the ISO would be an economic dispatch and associated balancing service. Based on day-ahead price offers (bids) from participating generators and consumers, the dispatch service would ensure that the residual needs for power, after accommodating all feasible bilateral contract deliveries, would be met by the least expensive mix of generation available at any given moment. The ISO's dispatch service would be used to provide both overall system balancing and an open, spot physical market to ensure moment-by-moment physical delivery even if the contract suppliers or consumers failed to perform as expected. To back up their contracts or just to engage in cash trades, market buyers and sellers would be free to use the ISO's spot market to buy and sell additional electricity whenever it was in their economic interest to do so.

Any supplier would be free to offer its generation to the ISO for dispatch and system balancing; any generator would be free to use the service to purchase additional supplies as needed. Ideally, consumers could also offer their dispatchable loads to the ISO or purchase spot electricity directly from the ISO's spot market. If the distribution utilities also remain in the generation business they too could participate in this service, both selling and buying power for their customers. The model does not require nor preclude divestiture of utility generation from distribution or transmission. Whether that step is necessary to deal with the potential abuse of market power or to allow a competitive market for energy services raises important questions that must be addressed.

The ISO's dispatch service would be voluntary. Any generator could offer to participate in the dispatch but none would be required to do so. A generator with a bilateral contract with one or more customers could choose to be part of the dispatch and respond to its spot prices, or it could choose to be outside the dispatch. Generators with contracts who chose not to participate in the ISO's voluntary dispatch would still have to notify the ISO of their planned operating schedules. The ISO would accommodate all feasible schedules, subject to network constraints and rules for curtailment. To the extent practical, the ISO would also accommodate efforts by generators and third parties to follow, shape and match specific loads associated with bilateral contracts. After accommodating bilateral contracts, the ISO would conduct its economic dispatch, balancing system loads and generation to maintain network stability and reliability.

A settlement mechanism would then charge consumers or buyers for the quantities they consumed and pay suppliers for the power they provided though the ISO's dispatch to the spot physical market. The charges and payments would reflect the marginal prices established by the competitive dispatch. In effect, the settlement mechanism would match anonymous buyers and sellers at a series of competitive market clearing spot prices.

Setting the market price for the short-term pool at the marginal price provides appropriate incentives for suppliers to bid their true costs and not to "game" their bids and for new market entrants to invest capital and compete.[2] In addition, allowing demand-side bidding in the pool, which we support, would provide additional competition. Of course, all consumers and suppliers would be able to enter into bilateral contracts with negotiated prices outside the pool.

Consumer choice and direct access would be directly enhanced and facilitated by the spot physical market offered by the ISO and the resulting spot prices. The ISO's dispatch and balancing services would provide the assurance of moment-to-moment physical delivery, essential to effective commercial trades. Similarly, the ISO's spot market would provide the supplier a ready market for its generation.

The prices offered to the ISO's dispatch service by generators and consumers would create a spot market and resulting spot prices. If the ISO accepted price offers for each hour or half-hour, the spot prices would change every hour or half-hour. Energy prices would thus vary over time with supply and demand, rising during peak demand periods and falling during low demand periods. Distribution utilities and competing customer-service companies could then pass the time-differentiated, market-based spot prices through to their customers, while consumers dealing directly with the ISO's dispatch service could receive those prices directly. This would allow consumers to react to the changing, time-sensitive price signals by adjusting their consumption as they saw fit. Those consumers with real-time meters could respond more precisely. But those without such meters could still respond to approximate real-time prices, based on typical load profiles for their customer class, or they could decide to install real-time meters on their own.

In addition, consumers would have the price information they need to decide whether to rely on such spot prices and accept their volatility or to contract with suppliers to lock-in or even-out prices over extended periods. Further, both consumers and suppliers, as well as their agents, could use the spot market to turn electricity into cash and cash into electricity. From this foundation, futures contracts and other tradeable financial instruments that enhance competitive markets could emerge.

Operation of the California Market Model would also provide important information about transmission costs. It would quickly become apparent from the generators' price offers that power costs would differ widely between generators, each located at different locations. The spot market price would be set by the price offered by the last generator (or the last dispatchable load) called upon by the ISO to balance total system generation and loads.

If there were no constraints on the transmission system, the same spot price would apply everywhere within the unconstrained area. This does not mean that all customers would pay the same price for all their power; any consumer would be free to contract with individual suppliers to lock in any price the parties could agree upon. The uniform price within an unconstrained area would only apply to the spot physical market; it would apply to those market participants who voluntarily chose to rely on the ISO's dispatch to provide that market and it would apply to any residual balancing service provided by the ISO after all third-party balancing efforts were accomplished. All contracts would have their own prices.

However, whenever there were constraints on the transmission system, as there often would be, the spot price would vary by location with one spot price prevailing on one "side" of the constraint and a different spot price prevailing on the other side of the constraint, each price reflecting the spot price of generation at each location. In a constrained network, spot prices would thus vary by location at some times. This variation is not a problem; it simply reflects the ranges in generation costs and the reality of the network and its current configuration. More important, the differences in locational spot prices provide the solution to the problem of efficient transmission pricing and the key to encouraging efficient investments for network expansion and new generation.

Transmission Pricing Under the California Market Model

In any competitive market, the price of transporting a commodity from one location to another should reflect the difference in the competitive prices for the commodity at each location. That is, a consumer at point "B" should never pay more to transport a commodity from point "A" than the extra cost of purchasing the same commodity at point B. The same is true for electricity. Instead of trying to "unbundle" transmission and determine the price of using each link along a designated contract path, transmission and generation can be priced simultaneously in a constrained network by taking the differences between the spot generation prices on each side of a network constraint.[3]

A simple example can illustrate this concept. Suppose the price of generation at location A is 3 cents per kilowatt hour and the price at location B is 5 cents per kilowatt hour. If there are no transmission constraints and enough generation at A, a customer at either A or B should pay only 3 cents for generation. But suppose there was insufficient transmission between A and B, so that not all the 3-cent generation consumers wanted from A could get to B. In that case, the price of generation for a consumer at A would still be 3 cents; but the price for a consumer located at B would be 5 cents.

If a consumer at B sought to purchase power from a 3-cent generator at A, it could sign a contract to pay 3 cents for the generation, but it would not be able to receive all of that power; that is, some portion of the generator's 3-cent power could not be physically transmitted to B because of network constraints. To enable the consumer at B to get its remaining power, generation at B would have to be used and its price would be 5 cents, raising the spot price for power delivered at B to 5 cents.

Continuing the example, if power had been offered to the ISO's dispatch service at these different prices, the ISO would have been offered power at A at 3 cents and power at B at 5 cents. Given the network constraint, some of the 3 cent power would not have been taken; instead, the ISO would have dispatched the remaining power at B, paying 5 cents. The consumer at B would have paid 5 cents for all its power, even though part of the power would have come from A at 3 cents. The difference between the 5-cent spot price paid to the ISO at B and the 3-cent spot price paid by the ISO at A would be 2 cents. The ISO would collect this extra 2 cents from the consumer at B for any power dispatched from A and then rebate that 2 cents to the network "owners" as a "congestion rental".

In the California Market Model any market participants would be free to become the owners of the rights to receive the congestion rentals. Transmission contracts would be allocated initially to the current owners and to those who had previously obtained various transmission rights. But current owners and contract holders would be placed in a system in which all transmission contracts could be freely traded. The consumers or generators in our example who faced a requirement to pay the congestion rentals would be free to purchase the contracts for these rentals, thus avoiding making the payments. The contracts for the rentals have been called "transmission congestion contracts". Holders of these contracts could sell them to any market participants to whom they were more valuable. In this way, those who placed the highest value on this protection could acquire the contracts using them to avoid the congestion rentals or to collect them from those who used the system. Market participants could also hedge uncertainty regarding such congestion payments through further financial instruments such as "contracts for differences", which we discuss in the next section.

Pricing network use by taking the locational differences in spot prices would provide important economic signals. In the simple illustration above, if the cost of adding more transmission to relieve the constraint were less than expected congestion rentals (or building additional generation at B), then the users at B would have an economic incentive to make that investment. And they would never pay more for the upgrade than the expected rentals because the total price for generation and the upgrade would exceed the price of generation available at B. Those faced with having to pay congestion rentals would be getting market-based price signals about whether to continue paying the rental, whether to buy the contracts to receive the rental, whether to build a transmission upgrade or whether to locate additional generation within the constrained area.

In conjunction with regional transmission groups (RTGs), system users would be in a position to plan and allocate the financing of appropriate network expansions. Network users who wished to avoid paying the congestion rentals could ask transmission owners to build upgrades to relieve the congestion, offering to pay the incremental costs. In conjunction with RTGs they could also ask FERC to order the owners to build such upgrades. Affected network users might even be in a position to build the upgrades themselves. The important point is that a system of congestion rentals and tradeable congestion contracts would provide efficient price signals about whether such transmission upgrades were economically justified.

Options Within the California Market Model

We do not expect that all utilities would be prepared to accept all elements of the California Market Model at the same time. But the underlying structure of the model is flexible enough to accommodate a range of acceptance by different utilities. Publicly-owned utilities may not be ready to allow their customers to participate in all of the direct access options for exercising customer choice that are possible under the California Market Model, but they could still choose to participate in a regional wholesale generation pool and spot physical market offered through the ISO's coordinated economic dispatch. They could also dedicate control of their transmission lines to the common, coordinated network, allowing the ISO to operate a regional network, ensuring that public utilities enjoyed open, comparable access to the entire network. Other utilities who were ready or whose customers demanded could offer one or more variations of the bilateral contract, direct access options possible under the model.[4]

The California Market Model could accommodate consumer choice through at least two types of bilateral contracts giving consumers direct access to the competitive generation market. The types vary principally on how they respond to prices from the spot physical market offered by the ISO. Consumers and suppliers would be free to choose either type or even to structure their contracts partly with one and partly with the other. Parties could also decide how much to rely on the physical spot market and how much to rely on the contract market. Flexibility to respond to market signals and individual economic needs would be the hallmark of the California Market Model.

In one type of direct access using "contracts for differences" the supplier and consumer would agree to a bilateral contract containing any price and other commercial terms the parties freely chose. The supplier would then offer its power at a price to the ISO's dispatch, agreeing to be dispatched up or down in response to the market clearing spot price revealed by the dispatch. If its generator plant was dispatched on, the supplier would receive the spot price from the ISO, while the consumer would pay the ISO, via the distribution utilitiy's rates, the spot price for amounts delivered via the physical spot market. Whenever the spot price was above the contract price, the supplier would rebate the difference to the consumer; whenever the spot price was below the contract price, the consumer would rebate the difference to the supplier. In either case, the parties would receive the benefits of their contract price. Even if the supplier was not dispatched on, the consumer would still receive its power via the physical spot market and pay the spot price for that power. Any difference between this spot price and the contract price would be rebated between the contracting parties, again leaving them with the benefit of their contract price.

The second type of direct access contract would function outside the ISO's physical spot market. Neither supplier nor consumer would bid generation or loads into the ISO's dispatch. However, the delivery schedules agreed to between supplier and consumer would be provided to the ISO and the ISO would accommodate all such schedules, subject to the physical operating limits of the network, including network constraints.[5]

As long as both supplier and consumer followed these schedules by matching generation and loads, the entire transaction would occur between the contracting parties with the consumer paying the supplier directly. Within transmission limits, the parties could provide their own balancing service or secure it from third parties, seeking to maintain the agreed upon schedules. Individual and third-party balancing would probably not be free to deviate too far from schedules submitted to and accepted by the ISO, particularly in a constrained network. At some point, the cumulative effect of unilateral, decentralized decisions by numerous generators operating outside the schedules could violate network constraints and pose a serious problem to the stability of the system, forcing the ISO to intervene. But any remaining imbalances resulting from a failure to maintain a perfect match would be covered by the ISO using the physical spot market. All such imbalances would be paid for at the spot price.

With either type of bilateral contract, many variations are possible, creating numerous options for exercising consumer choice. The California Market Model is indifferent to how large the participating consumer is or whether the contract deals with a single consumer or any aggregation of consumers. For example, individual retail stores within a larger chain or related industrial facilities could aggregate their loads. Whole industrial parks could do so.

Indeed, whole communities could aggregate their loads. Just as the ISO's physical spot market and coordinated dispatch could accommodate public utilities on the supply side, it could also accommodate entire communities, functioning under the concept of "community access", on the demand side. One community access proposal has been proposed to the CPUC by the consumer group Toward Utility Rate Normalization (TURN) as a way to maximize the competitive buying power of small consumers and to help them overcome the proportionately high transactions costs faced by individual consumers. By aggregating their demands a community buying agent could seek out beneficial contracts with competitive suppliers. To make community access work well, both elements of the California Market Model -- the ability to make bilateral trades and an open physical spot market to back up such trades and ensure moment-to-moment delivery -- would have to be in place. Indeed, these two elements of the California Market Model are prerequisites to the efficient working of every market model variation proposed by the parties to the debate.

This is only a summary of the California Market Model. More detailed descriptions that examine direct access options, bilateral contracts, futures contracts, the operations of the ISO, the workings and mechanics of the spot physical market, the intricacies of transmission congestion pricing and the definition and allocation of tradeable congestion contracts appear in numerous papers by participants in the California and national debates about restructuring.[6] Further detailed working papers have been prepared by participants in the various subcommittees of the Competitive Power Market Working Group.[7] Additional studies of transmission congestion contracts and their efficacy in providing efficient incentives for transmission investments have been completed at this Commission through consultant contracts.[8] In sum, a considerable literature already exists on how to build and implement the California Market Model.


The California Market Model gives equal emphasis to consumer choice, exercised through direct access bilateral contracts, and the operation of a spot physical market through an economic dispatch service offered by the ISO. It is essential to recognize both elements. We are convinced that the debate over market models, wherein parties have emphasized various elements of the complete model, will eventually reveal that many perceived differences are reconcilable and relatively straightforward to resolve.

One of the key issues concerning any market model is the potential for one or more entities to exert undue market power -- that is, to be able to charge a price consistently above what would be possible in a truly competitive market. We believe that one beneficial aspect of an ISO would be its ability to reveal, through its transparent pricing of generation and transmission congestion rentals, potential concentrations and abuses of market power. The Commission is engaged in ongoing studies of market power and will include that subject among the topics addressed in the 1996 Electricity Report (ER96).

Another serious issue that must be resolved is the issue of stranded costs. In a restructured market, some power plants that have not been fully amortized (as well as other utility obligations such as long-term qualifying facility contracts), may not be able to have their full costs recovered through competitive market prices. We make no recommendation here about the appropriate division of responsibility for stranded costs between ratepayers and shareholders nor about the most effective means of determining the magnitude of and collecting payment for stranded costs. Rather, we simply note that a sound resolution of this issue is necessary to allow for unbiased pricing of generation and to be fair to all parties. We will continue our investigation of this matter in ER 96.


The creation of a competitive electricity market is extremely challenging, requiring a balance between the need for decentralized market trades and the need for some central coordination of the interconnected transmission network. Pricing transmission service efficiently makes the challenge more difficult. There appear to be workable ways to meet these challenges. The California Market Model is the result of efforts by all parties to solve these problems. It combines the benefits of an efficient spot market coordinated by an independent system operator, the provision of comparable access to critical facilities and services, and the efficiency and consumer choice of a direct access contract market. It allows generators and consumers to exercise choice.

Debates about market models have tended to emphasize various pieces of the California Market Model, sometimes to the exclusion of other pieces. In this chapter, we have shown how all the pieces fit together to create a coherent picture, a unified electricity market based on efficiency, consumer choice and fairness to all participants.

In the next chapter (not available on the Internet), we examine some of the issues that must be resolved to enable an efficient electricity market to emerge. In particular, we examine additional steps that will be necessary at the customer level to make consumer choice a reality.


  1. (The National Energy Policy Act) EPAct authorize the Federal Energy Regulatory Commission (FREC) to require transmission owners to provide open, non- discriminatory access to third parties for the purpose of making wholesale trades. FERC decisions require that such access be made available on terms and conditions that are "comparable to those the owner provides for its own wholesale transactions. Recently, FERC proposed (late 1995) rules that would require all transmission owners to file open access traiffs that ensured comparability of service for all wholesale users. None of the federal efforts, however, extend open access requirements to "retail" transactions.

  2. Moreover, for utilities with "stranded costs," any "windfall" resulting from selling power to the pool -- from plants with costs substantially below the market clearing price -- could be offset as the windfall is credited against the stranded costs of power plants with costs above the market clearing price. (For further discussion of the determination of the pool's market clearing price and its effect on market behavior and investment decisions, please see the Commission's Reply Comments on CPUC Proposed Structure for a Competitive Electricity Industry [August 22, 1995].)

  3. The underlying principle of locational spot pricing and its application to electricity were first developed by Fred Schweppe, Richard Tabors and their colleagues at the Massachusetts Institute of Technology (M.I.T.).

  4. The flexibility offered to utilities by this model has earned it the name "Maximum-choice model," a description used by the Southern California Association of Public Power Authorities (SCAPPA) and the California Municipal Utilities Association (CMUA).

  5. The availability of this direct access option may depend on successful resolution of FERC/State jurisdictional issues related to transmission.

  6. Numerous papers have been prepared by Professor William Hogan (Harvard University), Larry Ruff (Putnam Hayes and Bartlett), Professor Paul Joskow (M.I.T.), Richard Tabors (M.I.T.), Sally Hunt and others at National Economic Research Associates, as well as Charles Stalon and Eric Woychik, the New York Mercantile Exchange, the Enron Company, Commission staff and others. Copies of these papers are available from the Commission.

  7. San Diego Gas & Electric, Southern California Edison, Pacific Gas and Electric, various municipal utilities, Recon Research Corporation, this Commission and others.

  8. Steve Stoft and James Bushnell, etc. "Transmission and Generation Investment In a Competition Electric Power Industry", UCEI, May 10, 1995.

Note for Internet Version:

The Internet version of the 1994 Electricity Report contains only the Introduction, Executive Summary, and Chapter 1. Copies of the complete printed version of ER94 are available from the Energy Commission's Publications Unit. There is no charge for individual copies. Please contact them at:

    California Energy Commission
    Publications Unit
    1516 Ninth Street, MS-13
    Sacramento, CA 95814

    Phone: 916-654-5200

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