In the post-Cold War era, we supposedly all understand the benefits of privatization
and the deregulation of markets. They bring efficiency, innovation, and lower
prices. Yet in California the attempt to form electricity markets arguably
a move away from regulation ended up with an embarrassing period of black
outs, significant price increases, and little in the way of innovation.
It didn’t have to turn out this way. Fundamental flaws in market design resulted
in serious problems when the market drifted into a supply-demand imbalance.
The California experience offers lessons not only about the design of electricity
markets, but about the operation of markets more generally. First, the institutional
structure of markets matters, especially in complicated industries such as electricity.
Second, it is hard if not impossible to capture the benefits of any market unless
prices are allowed to signal scarcity and surplus to buyers and sellers.
Third, policy makers should fully appreciate the reasons why particular industry
structures, (e.g., vertical integration between electricity generation and distribution)
have emerged over time, and disband them only with great care. Fourth, the intervention
of politics, acrimony and litigation are never propitious for any industry,
but especially not for one in a crisis that is also burdened with newly formed
or inexperienced institutions.
We’ll sketch the origins of the crisis and the major policy errors, then turn
to identify principles which, if followed, will fix the situation and restore
an investment climate sufficiently positive to support the new investment needed
to achieve an improvement in supply and more responsive demand. Because of the
complexities, our treatment is necessarily incomplete, but we believe we present
an accurate summary of the facts, a correct diagnosis of the policy errors,
and a forward-looking view of the reform opportunities.
Restructuring in California
The deregulation of banking, airlines, trucking, and to some extent telecommunications
preceded electricity, and consumers have been the beneficiaries. Admittedly,
electricity creates a special set of problems of its own arguably more
challenging than some other industries. In particular, with electricity the
ability to store the product is extremely limited, so generators must be motivated
to supply exactly the amount that customers want at any time.
This “load balancing” requires the active involvement of generators, transmission
companies, local distributors as well as customers, and arguably regulators
too. The conundrum in electricity restructuring is how to achieve the cooperation
necessary to maintain reliability in an interrelated industry, while simultaneously
effectuating the competition that’s required to bring about greater efficiency
and lower prices.
The introduction of competition in the United States has moved at different
speeds and in different manners in different states. California was one of the
pioneers beginning with a 1993 policy study.
Following authorizing legislation (California’s AB 1890 in 1996), this program
was implemented by the California Public Utilities Commission (CPUC) in cooperation
with the Federal Energy Regulatory Commission. As a result:
The California Power Exchange was set up to run an independent centralized
The California Independent System Operator (ISO) was established to operate
the transmission network owned by three investor-owned utilities.
The CPUC essentially required the Pacific Gas & Electric (PG&E) and Southern
California Edison to divest 50 percent of their fossil fuel generation capacity.
Rates for residential and small business customers were frozen at 90
percent of prior levels, with the rate cut financed by bonds they were obliged
Up to four years was provided for utilities to recover stranded costs
of prior generation investments, after which retail rates would be set competitively.
The CPUC required utilities to buy their entire net electricity needs
from the PX at spot, or near-spot prices only not through contracts with
Independent power marketers were authorized to sell electricity directly
to all customers for delivery over utility distribution systems.
Under the new structure, California electricity markets worked reasonably well
from April 1998 through April 2000. Wholesale electricity prices averaged $30/MWH,
customers enjoyed reduced frozen rates, many new power plants were proposed,
utilities progressed on stranded cost recovery, and retail competitors attracted
a substantial share of large customer loads.
However, the situation changed in the summer of 2000 when (both peak and off
peak) prices spiked up to nearly 10 times those of the previous two years, and
stayed at elevated levels for an entire year.
Regulatory constraints meant that the utilities could neither protect themselves
against high spot prices through long-term contracts nor pass on the higher
prices to their customers. The resultant financial squeeze forced PG&E and Southern
California Edison into insolvency, led to a 40 percent increase in retail rates,
killed retail electricity competition, began California’s slide into its current
fiscal peril, and led to recriminations and uncertainty from which the state’s
energy investment climate may not recover for many years.
The wholesale price increases that precipitated the crisis have been attributed
to a number of factors, including:
During the 1990s, capacity to produce and deliver electricity to users had
failed to keep up with growth in demand, amplified by:
Hot weather throughout the Western United States that increased seasonal
Reduced electricity imports due to reduced rainfall in the Pacific Northwest.
Rising, and ultimately skyrocketing natural gas prices.
Increasing costs of emissions credits needed for electricity generation
in the Los Angeles basin.
Lack of Demand Elasticity
Frozen retail prices gave customers no economic reason to curtail demand even
as the average wholesale cost of electricity soared.
Absence of Real Time Metering
There was no mechanism in the market to allow higher relative prices during
periods of peak use thus foregoing beneficial incentives to conserve
power when it was most valuable, and to reschedule use for time periods when
electricity market costs were lower.
Lack of Long-Term Contracts
The “buy-sell” rule kept utilities from protecting themselves against high
wholesale prices through entering long term contracts. Put differently, the
natural hedge contained in the industry’s prior level of vertical integration
was undone and not replaced when utilities were forced to divest
much of their generation capacity.
The market design adopted for the PX had a single clearing price in which all
generators/suppliers got the expected bid price required to clear the market.
A tight supply situation created the potential (at least in theory) for market
“manipulation” or supply “withholding” even by individual sellers acting
alone to raise the price of power traded in the market. The market design
chosen had important and serious implications for pricing behavior in the market,
and for questions of whether market participants may have withheld output to
cause prices to rise. Because of the importance and complexity of these market
power issues, they are explored in more detail below, albeit in a preliminary
and abridged fashion.
Figure 1: Monthly Costs for Energy and Ancillary Services for CAISO Control
Area per Dollars per MWh
Source: CAISO-DMA (2002a); CAISO-DMA (2202b)
Claims abound that the high market prices of May 2000 to June 2001 were largely
due to market manipulation and the exercise of market power by some electricity
producers and marketers. However, what seems obvious to some turns out to be
a rather complicated and very technical issue that turns on economic principles
many do not appear to appreciate.
Numerous governmental investigations and analogous lawsuits seem premised on
the belief that if electricity prices rose to levels several times those experienced
in recent years, then producers must have engaged in improper actions designed
to raise prices. As a matter of economic principle, this is quite simply wrong.
A firm has market power when it can price without regard to competition. More
technically, monopoly power is sometimes defined as the ability of a firm to
price above competitive levels and sustain that price for an extended period,
despite the actions of its competitors. In the California electricity market
with no demand responsiveness it was belatedly recognized that tight market
conditions might cause even a relatively small generator’s production decisions
to have price impacts when market conditions were tight, and most or all available
power generation was needed to avoid blackouts.
Embedded in these pricing issues is a resource allocation function of considerable
importance. In times of scarcity, market prices go up in ways economists recognize
as legitimate, important, and not necessarily an indication of market power.
So-called “scarcity rents” (the profits that result from scarcity) are a rational
way to allocate scarce supplies to those who most value them, and to offer a
strong incentive for entry by additional suppliers able to meet consumers’ demands.
High natural gas (input) costs can also cause high electricity prices. So can
the need for certain electricity generators (“peaking units”) to recover all
their costs during only a relatively few hours of operation each year.
Understanding why wholesale electricity prices rose in California requires
a careful assessment of these (and other) factors. Clearly, high prices alone
are not an indication of the presence of market power; they may simply reflect
fundamental scarcity. Indeed, the existence of prices above even long-run costs
occurs in many industries, and is usually eroded in due course by entry or expansion
of other providers.
Distinguishing market power from scarcity rents is sometimes an analytical
challenge. A key factor is the assessment of “withholding” of output. A producer
who is offering to the market all that is economic to produce is not exercising
market power even if prices are high like a landlord charging market
rents that far exceed a building’s historical construction cost.
An exercise of market power requires many elements and requires a contrived
shortage with the artificial shortage or shortfall not being replaced by increased
supplies from other providers. Contriving a shortage requires the firm to leave
some of its potential output unsold in order to sustain an above-market price.
This is why a focus on output and in particular, whether a firm is using
its available capacity to produce electricity is important to distinguishing
market power from scarcity rents.
Problems with the design of the California wholesale market complicate the
analysis of potential market power. The retail rate freeze imposed by the PUC
in conjunction with the determination of the ISO to avoid blackouts, created
a market where electricity demand held steady, regardless of price. Neither
customers, nor the ISO on their behalf, were able to respond to higher wholesale
prices by cutting back demand, as would occur in a normal market situation.
This made wholesale prices highly sensitive to small variations in available
generation output during high demand periods.
Accordingly, the diagnosis of market power (and the alleged “overcharges” that
might be associated with it) might potentially hinge on why, for example, a
relatively small amount of generating capacity might have been offline at a
given time. Even worse, because the CPUC’s “buy-sell” requirement forced the
bulk of market purchases to occur at spot prices, volatile prices affected roughly
half the state’s power bill at any given time volatility from which utilities
(and ultimately customers) could have been protected through the long-term contracts
the CPUC prohibited. In combination, these two market design errors created
an unfortunate situation that amplified the effects of many ordinary day-to-day
decisions by power plant operators.
Not surprisingly some analysts have tried to test for market power in California’s
electricity pricing. However, the observation that prices were above producers’
marginal operating costs (the test many studies have employed) is not especially
meaningful, especially where scarcity rents may exist, where opportunity costs
are significant (as when a hydroelectric system can utilize its water resources
now or later), where factors other than operating costs may be relevant, where
other regulatory limitations (such as air quality emission limits or taxes,
or new plants sighting delays) restrict output or raise costs, or where a flawed
bidding scheme may have offered incentives for above-cost bids.
The financial crisis caused by insolvency of the distribution companies likewise
created a risk that producers would not be paid for their electricity just as
natural gas prices (the essential input) reached record levels. Simple operating
cost-based offer bids would make no sense for a generator under such circumstances.
Arguments about whether particular power plants should have been running at
particular times have yet to yield persuasive evidence of strategic outages.
Our conclusion is that electricity markets should not be designed in such a
way that performance assessment involves subtle distinctions between acceptable
and unacceptable market behavior. The good news is that it is entirely feasible
to design markets that avoid the problems experienced in California.
Reforms That Work
The need for reforms in California has already been recognized by many market
participants and federal and state regulators, although the CPUC has tended
towards a revisionist command-and-control philosophy that will make matters
worse. California also bears a unique financial challenge due to the inept response
of the state’s officials to the crisis.
Concerns about price volatility, competition, and market power can be greatly
mitigated by adopting the following basic principles:
Open and free contracting between parties. The CPUC has already
recognized the error of its ways in prohibiting utilities from engaging in contracts
with power producers that would have mitigated risk for both parties, and ultimately
for customers as well. However, it is still not clear that the CPUC is willing
to forego the subsequent second-guessing of the merits of such contracts.
Eliminate barriers. California is notorious for its permitting
delays for new power plant construction, a process that extends a typical project
to about four years. The ability of new producers to readily enter the market
(or for existing producers to expand output quickly) is essential to maintaining
competition and limiting the scarcity rents that occur naturally. Free and open
contracting also reinforces rapid entry.
Implement real-time pricing. Real-time pricing is essential to
allow customers to shift their demands in response to what prices tell them
about when electricity is cheap, and dear. The wholesale market also needs to
feel the impact of such customer responses.
Minimize government’s role. There is clearly a role for government
oversight of electricity markets, especially in terms of establishing and policing
rules for wholesale markets and the related maintenance of reliable service.
But it would be incorrect to read the California crisis as a justification for
more traditional (and discredited) market intervention by government.
We don’t mean to imply that the implementation of these principles is either
politically or technically easy. They are not. However, there is sufficient
experience from other jurisdictions (in the United States and abroad) to provide
strong guidance on the technical issues. The political challenges are undoubtedly
considerable. But we do believe that one of the biggest problems the State faces
is that it has over-politicized electricity, and tried to obfuscate the reasons
for the crisis.
With the 2002 gubernatorial elections over, one can only hope that political
concerns can be subordinated to the public interest for a period sufficient
to allow reform opportunities to be embraced.