Share This
September 2001 Cover Art

Search Finance & Development

Advanced Search

About F&D


Back Issues

Write Us

Copyright Information

Free Email Notification

Receive emails when we post new items of interest to you.

Subscribe or Modify your profile

Finance & Development
A quarterly magazine of the IMF
September 2001, Volume 38, Number 3

Lessons from California's Power Crisis
John E. Besant-Jones and Bernard Tenenbaum

"This is a dreadful mess for a state that is held up around the world as a model of innovation. . . ."

The Economist,
January 20, 2001

Over the past 15 years, more than 30 countries or regions within countries have initiated major reforms of their power sectors. Typically, the reforms involve some combination of restructuring, privatization, and competition. While the reforms are almost always intensely debated by power sector officials, they rarely receive much attention outside the power sector. But this has changed with the skyrocketing prices, blackouts, utility bankruptcies, and potential "deprivatization" that have accompanied the collapse of California's reform program. Clearly, what happened in California was not what was planned.

It is not surprising that policymakers around the world are now asking questions. If things can go so badly with a reform that did not involve privatization in such a rich and sophisticated economy, what is the likelihood for success in much less well endowed countries embarking on the whole gamut of reforms, including privatization? It is also not surprising that prime ministers and power ministers in many developing countries are receiving telephone calls from opponents of power sector reform telling them "you are going to have another California" unless the reforms are stopped or scaled back.

There is no lack of information on the California crisis. Over the past 12 months, thousands of pages have been written on the crisis in industry journals and the popular press. As Newsweek columnist Robert Samuelson wrote in describing another crisis: "[G]etting information is not the problem; the hard part is deciding what it means" (July 17, 1995). This article attempts to assess what the California power crisis "means" for developing countries. While the crisis is far from over, there is, however, enough evidence to suggest some preliminary lessons.

Features of California's reform

In the early 1990s, California's average electricity prices were about 50 percent higher than the U.S. average. The state's economy was in a recession, and major industries were threatening to move to other states. The governor and his advisors concluded that the state's power sector needed major reforms to lower electricity prices to levels comparable to those in neighboring states. Their solution was to restructure the state's power sector and introduce wholesale and retail competition.

When the reform began in 1996, three privately owned utilities—Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E)—were the monopoly suppliers of about three-fourths of California's retail sales. These three utilities, known as investor-owned utilities, or IOUs, were vertically integrated monopolies—they generated, transmitted, and distributed electricity to retail customers who generally had no other supply options. The remaining 25 percent of the state's electricity consumers were served by municipal utilities, which were integrated to varying degrees.

The California reform program involved restructuring and competition. (It did not involve privatization because most of the power sector was already privately owned.) Its key elements were

  • mandatory divestiture of 50 percent of the IOUs' fossil-fuel generating plants but without any contracts to buy back the output of the plants;

  • mandatory participation of the IOUs, both as buyers and as sellers, in centralized spot wholesale markets for day-ahead and day-of power sales run by a new organization called the Power Exchange (PX);

  • creation of the nonprofit Independent System Operator (ISO) to take operational control of the high-voltage transmission grid that continued to be owned by the IOUs;

  • introduction of retail competition or customer choice with retail customers served by the IOUs now being allowed to switch to other electricity suppliers;

  • recovery by the IOUs of "stranded costs" (costs that were anticipated to be above future market prices) through a "competitive transition charge" to be paid by all retail customers; and

  • a mandated 10 percent reduction in, and freeze on, retail tariffs for four years or until the IOUs had recovered stranded costs, whichever came first. The 10 percent reduction was largely offset by the competitive transition charge.

Although participation in the new market arrangements was mandatory for the IOUs, municipal utilities were given the option of not participating, and most of the municipal utilities chose that option.

The crisis

California's reform program seemed to work reasonably well for the first two years. But it began to fall apart in the middle of 2000. Prices in the day-ahead wholesale market jumped by more than 500 percent between the second half of 1999 and the second half of 2000. And in the first four months of 2001, these wholesale prices continued to climb to an average of more than $300 per megawatt-hour, or roughly 10 times what they had been in 1998 and 1999. As a consequence, the total annual cost of wholesale electricity for California increased from $8 billion in 1999 to $28 billion in 2000 and could reach $30-50 billion for this year. The principal beneficiaries of the higher revenues, according to California's governor, Gray Davis, were out-of-state generators he described as "pirates" and "marauders." But more recent evidence shows that some of the highest wholesale market prices were actually charged by government-owned utilities located both inside and outside California. A recent attempt to mediate the disputes over "overcharges" and "nonpayments" involved daily negotiations in Washington among more than 150 high-priced lawyers and lasted for more than two weeks. Ultimately, the negotiations failed.

Compounding the price shocks was the fact that California's two largest utilities, PG&E and SCE, have not been allowed to pass the higher costs of power through to their retail customers. With unfunded liabilities of several billion dollars, PG&E was forced to declare bankruptcy in April of this year. At the time of this writing, SCE is trying to avoid a similar fate by negotiating the sale of its high-voltage transmission grid to the California state government to raise cash.

High prices have not been the only problem. California has also experienced major shortages of supply. During this past winter, California's retail customers experienced their first blackouts in decades, with a cost to the California economy of several hundred million dollars.

The federal and state governments have tried a number of "quick fixes" to deal with the crisis. More than 100 bills and resolutions have been introduced in the California legislature. When power suppliers refused to offer supplies to California buyers because they were afraid they would not be paid, the federal government and courts ordered generators to continue to supply the power. To reduce day-to-day supply shortfalls, a state agency began purchasing short-term power on behalf of California consumers and also entered into fixed-price, longer-term contracts. As in many developing countries that lack generation capacity, state government officials are now considering statewide reductions in voltage to get more supply out of existing generating capacity. The governor has also proposed that the state purchase transmission facilities owned by PG&E and SCE and create a state government-owned power authority to build new power plants. More recently, several prominent California politicians have threatened to "seize" the power plants owned by private generating companies. It is perhaps not surprising that one independent power developer was quoted in the Los Angles Times (March 27, 2001) as saying: "Generators find it more predictable and less risky to do business in Third World countries than they do in the state of California."

Some lessons for developing countries

So what does all of this mean for developing countries? It appears that the principal lessons relate to sequencing, market design, and regulation.

A wholesale, bid-based, spot electricity market is not the highest priority for power sector reform in many developing countries. A key element of the California reform was the creation of a mandatory, bid-based spot market (a market in which sellers are free to bid any price) for most of the major California utilities. It was a large exercise that took about four years and cost more than $100 million to implement.

Although a spot market can provide helpful price signals to consumers and potential investors when the necessary conditions (see below) are in place, it should not be the highest reform priority in a developing country with a power sector characterized by underpricing, significant cross-subsidies, widespread overstaffing, large technical and commercial losses, and pervasive political interference in operating and investment decisions. At a recent World Bank conference, a consultant who has worked on power sector reform in more than 20 countries observed that the highest priority for most developing countries is "not the creation of a sophisticated spot market, but charging tariffs that collect costs and then collecting the bills." The danger of trying to create a California-style spot market in many developing countries is that it will be a very time-consuming and expensive distraction, while more basic problems (that reflect larger inefficiencies) will be ignored. And if the reform effort fails because of misplaced priorities, the country may lose a once-in-a-generation opportunity to make major improvements a

A wholesale, bid-based spot market should be pursued only under certain conditions. These conditions include no major regulatory barriers to the construction of new generating plants, the absence of pervasive market power, a regulatory system that allows retail tariffs to cover distribution companies' costs, the availability of mechanisms that allow buyers and sellers to hedge against price volatility, a transmission system that is relatively free of physical bottlenecks, the existence of market and system operators that are independent of buyers and sellers, and the presence of major power consumers that are able to change their demand in response to fluctuations in the spot market. Some of these prerequisites are also required for more limited forms of competition. But the consequences—for example, extremely high price spikes—of failing to satisfy these conditions are more noticeable and harmful in a deregulated spot market. In general, it is more difficult to create a spot market in electricity than in other energy commodities, such as oil and gas, because the impossibility of storing electricity at a reasonable cost makes electricity generation the ultimate "just-in-time" production process.

Start with more limited forms of competition that can evolve into bid-based spot markets. Because the prerequisites for bid-based spot electricity markets are not easy to satisfy, policymakers in developing countries should consider other, more limited forms of competition that can later evolve into a deregulated, bid-based spot market. For example, successful cost-based spot markets have been established in several Latin American countries. In a cost-based spot market, generators are required to bid their actual or estimated variable production costs. The two principal advantages of this type of market are that it provides more protection against the exercise of market power and that it represents a relatively natural extension of the preexisting systems used to determine the order of least-cost production among generators owned by publicly owned, vertically integrated power systems.

A cost-based spot market will not block moving to a bid-based spot market, once the prerequisites are in place. But it should be recognized that a country's size affects its choices. It may simply be impossible to create workably competitive bid-based spot markets in the more than 100 countries with less than 1,000 megawatts of installed generating capacity without constructing significant transmission interconnections to neighboring countries to increase the size of the market.

Another form of competition is the single-buyer model. Under this model, there are no spot markets. All electricity is procured by an entity specifically mandated to perform this function, and this entity is also the exclusive seller of wholesale power to distributors and other large users. This is a "toe in the water" approach because it allows competition only for onetime procurements of relatively well defined products—namely, the supply of base, intermediate, or peaking power for a specified period of time. There is no ongoing competition among generators on an hourly or daily basis.

Although this model is easier to implement, the disadvantage is that the single buyer is usually a state-owned enterprise that is often not a skilled buyer. The single buyer may also be susceptible to pressure from political authorities to sign high-priced and poorly designed long-term power-purchase agreements. Outside observers have argued that this has happened in countries as diverse as the Dominican Republic, Guatemala, India, Pakistan, and Indonesia. California was forced to move to the single-buyer model in early 2001 when generators in California and neighboring states were no longer willing to sell power to the two large private distribution entities because they doubted the latter's ability to pay. A state agency was given temporary responsibility for buying wholesale power from generators using the state's general credit and then reselling it to the distribution entities. As of this writing, there are already allegations that the state paid too much for this power.

Some countries are experimenting with a hybrid market model that is usually described as a "multi-buyer, multi-seller model." Under this approach, buyers procure power, either individually or through buying cooperatives, and then rely on a central "imbalance" market to acquire or sell any differences between the power received under the contracts and their actual hourly consumption. It remains to be seen whether this will be a viable alternative to a spot market or the single-buyer model.

Allow vesting contracts as a form of insurance for distribution companies purchasing from a new spot market. Before any spot market goes into operation, the government or its privatization agency should establish contracts between existing generators and distribution companies that fix the sale price of power for five or more years. Vesting contracts provide "insurance" in case flaws are found in the market design, and they provide revenue and cost certainty to generators and distributors in the early years of reform.

In most countries that have created spot or short-term wholesale markets, vesting and other hedging instruments cover as much as 80-90 percent of the total power trade. However, this was not the case in California. The three IOUs were forced to sell off their generating plants without any vesting contracts and were effectively prohibited from pursuing any hedging arrangements until fairly recently. In effect, they were required to purchase almost all of their supply needs in the newly created spot market. This is the functional equivalent of requiring that all passengers on a particular plane flight buy their tickets in a mandatory auction that takes place 30 minutes before the scheduled departure.

Save full retail competition for last. Retail competition did not succeed in California for several reasons relating to specific design features of the California retail competition program (for example, the 10 percent mandated rate reduction combined with a rate freeze and recovery of stranded above-market costs through a competitive transition charge that all suppliers—new and old—were required to recover from their retail customers). But even if California had been successful in introducing retail competition, this does not imply that most developing countries should rush to introduce full retail competition as soon as they embark on reforms.

Full retail competition—giving every retail customer the right to pick an electricity supplier over an existing network—is expensive and complicated to implement. In England and Wales, it has been estimated that the initial hardware (metering, data transfer, and telecommunications systems) and software have cost more than $1 billion so far. Some countries—Australia and Norway—appear to have had more success than California with full retail competition. But it is also important to remember that these countries, like California, started from a base of full household electrification. In countries that have not achieved substantial household electrification, it will probably be more productive to focus on encouraging competition to serve those who do not currently have access to electricity, rather than on retail competition for those who are already supplied. This could be accomplished through competition for the right to receive a government subsidy (for capital or operating costs or both) in return for an obligation to provide a specified level of grid or off-grid service. This approach has been successful in Chile and Argentina.

Ensure that retail tariffs cover all costs. It is virtually impossible to undertake any serious power sector reform (including the creation of spot markets) unless a government is politically committed to creating a regulatory system that will close any initial revenue-cost gap and prevent that gap from reopening by allowing any reasonably efficient distribution company to recover its purchased power and distribution costs. The California regulatory system did not satisfy this requirement. Instead, the largest distribution utilities were caught in a squeeze between deregulated and volatile wholesale spot market prices and regulated, fixed retail prices. By the fall of 2000, the distribution utilities were buying power that averaged about 20 cents per kilowatt-hour and were forced to resell that power for about 6 cents per kilowatt-hour. The governor of California was quoted in the Los Angeles Times as saying: "Believe me, if I wanted to raise rates, I could have solved this problem in 20 minutes" (March 29, 2001). By the time the California regulatory commission decided to raise the average retail tariff, it was too late—PG&E was already in bankruptcy and SCE was teetering on the brink.

Both sides of the market must see the market price. California created a "one-sided market." Both small and large customers were generally insulated from the price fluctuations in the spot market. Obviously, consumers will not respond to high prices if they never see them. Moreover, if final customers do not see the prices that are being paid on their behalf, it becomes easier for generators to abuse any latent market power. A study by the U.S. Electric Power Research Institute has estimated that if "real-time pricing" had been offered on a voluntary basis to commercial and industrial customers, it could have reduced peak demands by 2.5 percent and wholesale prices by almost 25 percent. This suggests that any reform program that creates a spot market must pay special attention to ensuring that real-time meters are installed on the premises of at least the largest customers so that they can see and respond to the real-time fluctuations in electricity prices. In most instances, this will create a win-win outcome: it will be good for the market as well as for the environment.

A competitive electricity market will not be sustainable if environmental and economic regulations prevent supply from responding to demand. A major failing of the California reform was that supply was not able to respond to demand. After a period of sluggish demand growth in the early 1990s, electricity demand growth picked up in the late 1990s with the Silicon Valley boom. Supply, however, did not increase much during the 1990s because (1) uncertainty about the new power market deterred investors until the new market structure and regulations were finalized in 1996, and (2) subsequently, excessive delays occurred in the award of siting permits for new power stations. Economists tend to forget that a market can be perfectly designed but will still fail if environmental and economic regulations prevent a timely supply response.

California has very stringent environmental standards. However, the problem was not so much the standards themselves but how they were implemented. Specifically, it took almost twice as long to get state and local siting and permitting approvals for new generating plants in California as it did in any other state. The California legal and political systems allowed residents near the sites of proposed facilities and environmental groups to block or substantially delay the siting and permitting process for most new generating plants. As a consequence, supply stagnated while demand steadily increased.

Purchase power regulations are also critical to the operation of a wholesale market. As noted above, California's major distribution utilities were forbidden by the state regulator from entering into long-term contracts with potential suppliers. In effect, the distributors were forced to "buy short and sell long." The fact that distributors were required "to go naked in the spot market" (that is, were prohibited from hedging for price volatility) made them especially vulnerable to any imperfections in the spot market. But supply problems have arisen even in countries that allow distribution utilities to enter into long-term contracts. For example, the distribution utilities of Argentina have had no incentive to take the risk of buying power under intermediate- or long-term contracts because the regulator has limited pass-through of purchase power costs to a seasonal index of expected spot market prices. In general, generation supply will not be forthcoming unless the regulator gives buyers incentives to enter into all types of purchases, not just spot purchases.

Governance of the transmission system and market operators should be kept independent of market participants, and it should not be susceptible to deadlock. In any organization, governance refers to what decisions are made, who makes them, how decisions are enforced, and how disputes are resolved. In a competitive power system, the transmission system and market operators must be able to make decisions independently of market participants to ensure equal, nondiscriminatory access to the high-voltage grid and the marketplace.

Independence can be achieved directly by prohibiting market participants from having an ownership interest in the system or market operator and requiring that the governing board be composed of nonmarket participants (that is, non-stakeholders). California did not choose this approach. Instead, it opted for a stakeholder board on the presumption that independence could be achieved through a diffusion of voting power among competing commercial interests. But the California governance arrangements failed for at least two reasons: the boards were too large (each had 25 voting members), and they were susceptible to vetoes by one or two classes of market participants. As a consequence, the boards were often deadlocked on key decisions. In theory, the regulator could have stepped in to break the deadlock. But this did not work in practice because there were two regulators, one state and the other federal, and they often did not agree. The California experience suggests that stakeholder boards will work only if they are limited in size, voting rules ensure that one or two classes cannot control the board's decisions, and a single regulator can step in when there is a deadlock.

This article is based on a longer paper, "California Power Crisis—Lessons for Developing Countries," published by the Energy Sector Management Assistance Program, a joint program of the World Bank and the United Nations Development Program, and the World Bank Energy and Mining Sector Board, in April 2001. The paper is available on the web at

John E. Besant-Jones is a Lead Economist, and Bernard Tenenbaum is a Lead Energy Specialist, in the Energy and Water Department of the World Bank's Vice Presidency for Private Sector Development and Infrastructure.