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.
FIGURE 1
Comparison of California and U.S. System Average Rates
1970 to 2013
Sources: 1970-1992 EIA; 1993 EEI.
FIGURE 2
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.
FIGURE 3
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.
ELEMENTS OF A COMPETITIVE ELECTRICITY MARKET
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.
CONFRONTING THE TRANSMISSION CHALLENGE
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 CALIFORNIA MARKET MODEL
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 DEBATE OVER MARKET MODELS
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.
CONCLUSION
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.
END NOTES
- (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.
- 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].)
- 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.).
- 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).
- The availability of this direct access option may depend on successful
resolution of FERC/State jurisdictional issues related to transmission.
- 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.
- San Diego Gas & Electric, Southern California Edison, Pacific Gas and Electric,
various municipal utilities, Recon Research Corporation, this Commission and
others.
- 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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Page Updated: February 5, 1996
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