CONGRESS OF THE UNITED STATES

CONGRESSIONAL BUDGET OFFICE

A

CBO

PAPER

SEPTEMBER 2001

Causes and

Lessons of the

California

Electricity

Crisis

© Royalty-free/Corbis

CAUSES AND LESSONS OF

THE CALIFORNIA ELECTRICITY CRISIS

September 2001

The Congress of the United States

Congressional Budget Office

PREFACE

This Congressional Budget Office (CBO) paper looks at California’s attempt to

restructure its electric utility industry and at the crisis in the state’s electricity market

that began in 2000. The paper focuses on the various conditions in western states that

put stress on California’s energy market. It also examines some of the elements of the

state’s restructuring plan that turned that stress into a crisis.

Richard Farmer of CBO’s Microeconomic and Financial Studies Division and

Dennis Zimmerman of the Tax Analysis Division, along with Gail Cohen, formerly of

CBO, wrote the paper under the supervision of Roger Hitchner, Tom Woodward, and

David Moore. Amy Abel of the Congressional Research Service provided useful

comments, as did William Hogan of the John F. Kennedy School of Government at

Harvard University and Douglas N. Jones of the School of Public Policy and Management at Ohio State University.

Christian Spoor edited the paper, and Leah Mazade proofread it. Angela Z.

McCollough prepared the paper for publication, Lenny Skutnik produced the printed

copies, and Annette Kalicki prepared the electronic versions for CBO’s Web site

(www.cbo.gov).

Dan L. Crippen

Director

September 2001

CONTENTS

SUMMARY vii

WHAT HAPPENED IN CALIFORNIA'S ELECTRICITY MARKET? 1

Before Restructuring 2

The Restructuring Plan of 1996 6

Market Developments from 1996 Through 2001 10

WHAT ROLE DID THE RESTRUCTURING PLAN PLAY? 17

The Price Freeze 19

The Restrictions on Long-Term Contracts 21

Flawed Auction Markets, Price Caps, and Market Power 23

Regulated Power Markets in California and the Rest of the West 24

CALIFORNIA’S RESPONSE: A NEW ROLE FOR 

STATE GOVERNMENT 28

The New Purchasing Agency 28

Implications of the State’s New Role 30

LESSONS FOR FUTURE RESTRUCTURING EFFORTS 31

Supply-Side Lessons 31

Demand-Side Lessons 32
vi CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

TABLES

1. Electricity-Generating Capacity in the Western States, 1995-1999 13

2. Net Electricity Generation from Hydropower and Natural Gas in

11 Western States, First Nine Months of 1999 and 2000 15

FIGURES

1. Who Sells to Whom in California’s Electricity Market 2

2. Electricity Consumption in California, 1985-2000 11

3. Prices That California Utilities Paid for Natural Gas, 

January 1999 Through December 2000 16

4. Average Prices That Utilities Paid for Electricity in the 

California Power Exchange’s Day-Ahead Auctions, 

April 1998 Through December 2000 18

BOXES

1. A Chronology of Electricity Restructuring in California viii

2. Municipal Utilities and the Federal Tax Exemption for 

State and Local Bonds 26
SUMMARY

The 1996 law that restructured California's electricity industry was intended to be the

first step toward lower electricity prices for 70 percent of the state's population. Few

observers foresaw the situation that would exist in California by the summer of 2001.

Just five years after restructuring became law, the state’s electricity market was

commonly described as being in crisis. The goals of restructuring—lower prices for

residential customers and more competitive prices for industrial customers—seemed

farther away than ever.

This paper addresses four questions:

• What happened in California's electricity market from the mid-1990s

through the middle of 2001?

• What role did the state’s restructuring plan play in those events?

• How did California respond to its market problems?

• What can other governments learn from California's experience?

Developments in the Electricity Market

California began the formal process of restructuring its electricity market in 1994 (see

Box 1 for a chronology of that restructuring). In doing so, the state was building on

federal actions dating back to the late 1970s that were intended to increase competition in electricity markets throughout the nation. By 1996, a restructuring plan was

enacted to change the sources and pricing of electricity for customers of three large

investor-owned utilities: Pacific Gas and Electric, Southern California Edison, and

San Diego Gas and Electric. Together, those utilities served almost three-quarters of

the state’s electricity users. (The rest were served mainly by publicly owned, or municipal, utilities, which were not covered by the plan.) California’s restructuring plan

was based on the assumption that greater competition among independent power

generators would cause wholesale prices for electricity to fall. That assumption

seemed reasonable in part because in the mid-1990s, generating capacity in the

western states exceeded the demand for electricity by roughly 20 percent.

By the summer of 2000, however, demand for electricity had outpaced the

generating capacity available to supply the market. The reasons for that change

included increases in the demand for electricity throughout the region (because of

economic growth and weather) as well as losses of hydropower capacity and other

conditions that limited power supplies. In that setting, the restructured wholesale

market pushed electricity prices to unanticipated levels.
viii CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

BOX 1.

A CHRONOLOGY OF ELECTRICITY RESTRUCTURING IN CALIFORNIA

1994: The California Public Utility Commission (PUC) begins a formal rulemaking procedure

to consider approaches to restructuring the state’s electricity market. That action builds on

changes in federal law and regulation that began with the Public Utilities Regulatory Policy Act

of 1978 and continued with the Energy Policy Act of 1992.

1996: California law AB 1890 codifies various regulatory changes and initiatives by the PUC.

Those changes include requiring the state’s three major investor-owned utilities—Pacific Gas and

Electric (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric

(SDG&E)—to sell half of their fossil-fuel capacity (they eventually sold all of it); transferring

control of electricity transmission to a newly created nonprofit corporation, the California

Independent System Operator (CAISO); creating another nonprofit corporation, the California

Power Exchange (PX), to run wholesale auctions of electricity; and freezing retail electricity

prices until 2002 (or such time as the utilities recover certain costs). The California state auditor

reports that the western states as a whole have excess generating capacity of roughly 20 percent.

1998: The California PX begins operating at the end of March. Between August 1998 and

March 1999, market-monitoring, surveillance, and market-analysis groups of the PX and CAISO

issue reports expressing concern about the functioning of California’s wholesale electricity

market.

June 1999: The CAISO’s Surveillance Committee recommends that investor-owned utilities be

granted more authority to enter into long-term contracts.

July 1999: SDG&E recovers its stranded costs (the decline in the value of certain assets, such

as generating facilities and long-term contracts with other suppliers, because of restructuring).

As a result, it is allowed to charge its customers market prices for electricity.

2000: Growth of income in California and neighboring states—which affects the demand for

electricity—accelerates. In California, total personal income, which had grown steadily since the

restructuring debate began, jumps by about 9 percent from its level in 1999.

April 2000: The price that California’s electricity generators pay for natural gas begins to climb

from about $3.50 per thousand cubic feet (reaching more than $6 by November).

May 2000: The summer cooling season begins. May and June 2000 rank among the 15 hottest

May-June periods of the past 100 years.

June 2000: Rising wholesale prices for electricity consistently exceed the frozen retail price. As

a result, PG&E and SCE must sell purchased power at a loss. Customers of SDG&E, by contrast,

pay the market price, which is three times higher than it was the previous summer. On June 14,

PG&E interrupts service for the first time in its history, which affects 100,000 customers in San

Francisco.

August 2000: The estimated annual prices that generators pay for pollution credits—which

reflect the costs of producing electricity from fossil-fuel plants—rise to $30 per credit (from $10

in June). They reach $45 per credit by December.
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS ix

BOX 1.

CONTINUED

September 2000: California enacts a law rolling back and freezing retail rates for SDG&E

customers at the 1996 level.

October 2000: The PUC permits Southern California Edison to increase its short-term

borrowing authority from $700 million to $2 billion to pay for power in the wholesale market.

November 2000: PG&E and SCE file for rate increases to cover power costs they could not

collect from consumers. The Federal Energy Regulatory Commission (FERC) releases a report

describing how market design and flawed regulatory policies in California have contributed to

high prices.

December 2000: The CAISO declares many Stage 3 emergencies, warning of the prospect of

blackouts as electricity reserves (the amount by which available generating capacity exceeds

demand) fall below 1.5 percent during periods of peak demand. The U.S. Department of Energy

orders electricity generators outside California to sell to the state’s wholesale market. FERC

imposes “soft” price controls (limits that may be exceeded in emergency circumstances) and

directs California’s investor-owned utilities to negotiate long-term supply contracts and reduce

their reliance on the wholesale market.

January 2001: The PUC approves retail rate hikes for PG&E and SCE. The CAISO orders

rolling blackouts on several occasions. Emergency orders by the governor direct the state’s

Department of Water Resources to buy power in response to the deteriorating financial condition

of the three large investor-owned utilities. The PX suspends operations.

February 2001: The state negotiates and signs long-term agreements to buy power. It begins

implementing a strategy intended to restore the financial health of the utilities, which includes

having the state purchase major transmission lines.

March 2001: Rolling blackouts occur statewide. FERC directs 13 power suppliers to refund $69

million that it says they overcharged utilities in January. The PUC approves immediate increases

in retail rates.

April 2001: PG&E declares Chapter 11 bankruptcy. Standard & Poor’s downgrades California’s

bond rating (from AA to A-plus) because of the state’s additional borrowing to address its electricity problems.

May 2001: California authorizes a $13 billion bond issue to finance its purchases of electricity.

The North American Electric Reliability Council warns that the state could face 260 hours of

rolling blackouts during the summer.

June 2001: FERC announces a price-mitigation plan for all of the western states, with wholesale

prices to be capped at a level reflecting the highest cost of generating electricity in California.

July 2001: Moderate temperatures help keep the demand for electricity lower than during the

previous summer. Even though water levels in the streams used to generate hydropower are low,

declining demand for electricity and falling natural gas prices combine to push wholesale

electricity prices to the lowest level since the spring of 2000. Prices in the spot market fall far

below the level that the state is paying for electricity under its long-term contracts.
x CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

As the three large investor-owned utilities faced spiraling financial difficulties,

and disruptions in electricity supplies appeared possible, some observers began to

question whether the old regime (power monopolies overseen by state regulators) did

a better job of meeting the demand for electricity than the new ideal (many independent producers interacting with consumers in a deregulated market). Observers

pointed out that the parts of the California market outside the restructuring plan

(mainly in the Los Angeles and Sacramento areas) faced fewer problems than the rest

of California, as did the other western states. By mid-2001—in the wake of one

bankrupt utility, even higher wholesale prices, and rolling black-outs—skeptics

blamed deregulation for putting California in a perilous position.

The Role of Restructuring

Much of the blame for California’s electricity crisis attaches to the state’s restructuring plan—but not to its objective, electricity deregulation. The state’s plan gained

political support on the basis of what turned out to be faulty assumptions. It then

played a role in turning market stresses—high demand for electricity and limited

production capacity—in the summer of 2000 and beyond into a full-blown crisis, in

which California’s major utilities could not buy enough power to supply their

customers. But deregulation itself did not fail; rather, it was never achieved. 

The restructuring plan did not remove sufficient barriers on both the supply and

demand sides of the market to allow competition to work—in part because it was not

designed to. Neither the state legislature and Public Utility Commission (PUC),

which framed the plan, nor the Federal Energy Regulatory Commission, which

approved it, envisioned the immediate or full deregulation of the electricity market

covered by the plan. Instead, retail prices were to be frozen during an interim period.

After that, the PUC would continue to oversee how much the utilities could charge

their retail customers for generating or distributing electricity.

In addition, the market outside the restructuring plan mostly remains regulated.

The California PUC has no authority over municipal utilities in the state, utilities in

neighboring states, federal power agencies, or interstate transmission companies. All

of those entities are still subject to local and federal controls. The continuing regulation of utilities in other parts of California and in neighboring states contributed

indirectly to California’s supply problems by limiting how much power those utilities

were able or willing to sell outside their traditional service areas.

Even without restructuring, California’s electric utilities would have faced a

difficult challenge in meeting the demand for power and holding down prices in 2000.

But at several key points during the unfolding crisis, features of the restructuring plan

limited the responsiveness of the supply and demand sides of the electricity market.
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS xi

Consequently, wholesale electricity prices were higher than they probably would have

been in either a traditionally regulated market or a more fully deregulated market.

On the supply side, the plan's freeze on retail prices left the three big utilities in

a financial shambles when wholesale prices in the spot market—where those utilities

were acquiring nearly half of their power—rose above the freeze level. The plan

made the utilities particularly dependent on that market in two ways: it encouraged

them to sell their fossil-fuel generating capacity, and it discouraged them from signing

new long-term supply contracts that could have protected them from adverse movements in prices.

Faced with a universal-service requirement (they could not unilaterally drop

customers) and with a negative cash flow on nearly half of their sales, the utilities saw

their losses mount. Lenders downgraded their creditworthiness, thus raising their

costs for new borrowing. Moreover, independent power generators were able to push

up wholesale prices further and even withdrew supplies when it looked as though the

utilities might not be able to pay for their purchases. That happened in part because

elements of the plan’s auction system for the spot market appear to have created

strong incentives for suppliers to bid strategically in a way that raised wholesale

prices. Some generators may also have withheld supplies at certain times to boost

prices even more.

On the demand side, two problems coincided. Extreme weather and strong

economic growth put stress on the market by increasing the use of power. At the

same time, the freeze on retail prices magnified the impact of that stress on wholesale

prices by eliminating incentives for consumers to conserve power. Even a small drop

in electricity use—like the decline that occurred in San Diego when the price freeze

there was temporarily lifted—would have been enough to let the state avoid some of

the disruptions it has faced.

The State’s Response

The developments in California’s electricity market and the failure of the state’s

restructuring plan provoked a political crisis. At the direction of the governor, the

state began taking steps in January 2001 to help secure future electricity supplies and

stabilize wholesale prices. The state has assumed a new role in purchasing wholesale

power on behalf of private utilities. It is also moving toward establishing a stateowned utility that, in addition to buying power, would own an extensive transmission

grid and build new generating plants. Moreover, the state has abandoned the retail

price freeze, raising rates to ensure that consumers help cover its costs of buying

power.
xii CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

In addition, the state has negotiated long-term contracts, lasting up to 20 years,

with electricity suppliers. The potential cost of that intervention became apparent in

the summer of 2001 when electricity prices in the spot market dropped in response

to mild weather and lower demand, falling below the price the state was paying under

its long-term contracts. If that situation persists, Californians could be committed to

paying high electricity prices for many years to come—the prospect that led to

restructuring in the first place.

Lessons for the Future

Market restructuring and concerns about electricity prices and supplies are still

important issues in many parts of the country. This past summer, the California

market returned to a semblance of normalcy because of slower economic growth,

moderation in the extreme weather conditions that had boosted demand for electricity,

and a decline in the high prices for natural gas that had inflated the cost of generating

power. But the electricity market in the western United States is likely to remain vulnerable to new stresses (for example, water levels in streams used to generate hydropower remain low). Some observers have warned that the problems in California

might appear in other states.

California responded to its immediate concerns about the availability of electricity and the volatility of prices by directly intervening in the market—a response

that could prove costly to electricity consumers and taxpayers. Long-term solutions

to California’s electricity problems will most likely require three changes: removing

barriers to the addition of generating capacity, eliminating bottlenecks in the electricity transmission system, and removing regulatory restrictions on the sale of power

throughout the broad western market. Those actions would help make the supply of

electricity more responsive to changes in prices. On the demand side, the prospects

for successful restructuring would also improve if consumers faced the full costs of

electricity and were better able to adjust their use of power in response to changing

prices.
1. In spot markets, transactions are made for immediate delivery (unlike futures markets, where transactions are made for delivery from one month to one year in the future).

2. For a discussion of early pressures on the electricity market, see California State Auditor, Energy

Deregulation: The Benefits of Competition Were Undermined by Structural Flaws in the Markets,

Unsuccessful Oversight, and Uncontrollable Competitive Forces (Sacramento: California State Auditor,

March 2001).

WHAT HAPPENED IN CALIFORNIA'S ELECTRICITY MARKET?

California's decision to restructure its electricity market came in response to changing

federal regulation of such markets beginning in the 1970s and to criticism of the

state’s market in the early 1990s. Consensus developed about two issues: first, that

regulated producers and markets delivered electricity at too high a price, and second,

that the future prospects for business investment in California were being hurt because

the state’s electricity prices were higher than those in other western states.

Electricity prices were high in California partly because the regulated market,

by assuring producers of a high rate of return on their investments, provided incentives to build too much generating capacity. Policymakers, however, considered such

excess capacity a saving grace of the system when California’s restructuring plan took

effect. Capacity in excess of demand was a key to ensuring that wholesale prices

would fall with competition. 

The plan required the state’s three large investor-owned utilities—Pacific Gas

and Electric, Southern California Edison, and San Diego Gas and Electric—to sell

part of their generating capacity. It also discouraged them from entering into longterm supply contracts with independent power producers. As a result, the utilities had

to rely on the newly created spot wholesale market for about half of the electricity

that their customers demanded.1

 (For more details about how the electricity market

in California operates, see Figure 1.)

California’s restructured electricity market functioned adequately at first,

although hot, dry weather throughout the West in 1998 put pressure on the system

(by increasing the demand for air conditioning and reducing the stream flows

necessary for generating hydroelectric power).2

 By 2000, however, it was clear that

capacity no longer comfortably exceeded demand. Since 1996, when the restructuring plan was enacted, generating capacity in California and the West had changed

little, although the size of the population and the economy—which affect the demand

for power—continued to increase. During the summer of 2000, the previous margin

of electricity reserves was eroded by further increases in demand for electricity

(because of economic and weather conditions) as well as by losses of hydropower

capacity and other supply circumstances. In response, electricity prices rose to

unheard-of levels. By 2001, utilities were facing bankruptcy, wholesale prices were

continuing to rise, and customers were experiencing rolling blackouts. Skeptics about
2 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

FIGURE 1. WHO SELLS TO WHOM IN CALIFORNIA’S ELECTRICITY MARKET

Electricity Wholesale Market Retail

Producers (Conducted through auctions Customersb

and bilateral contractsa)

SOURCE: Congressional Budget Office.

a. The California Independent System Operator conducts wholesale auctions of electricity. In addition, the California Power

Exchange conducted such auctions until it was shut down in January 2001.

b. California’s restructuring plan allowed customers to buy electricity directly from independent producers and brokers, but

virtually all customers stayed with their traditional utility supplier as long as the freeze on prices remained in effect.

c. Producers who use renewable energy sources or cogeneration (waste heat from industrial processes) to make electricity.

the restructuring plan blamed it for placing California in a perilous position and for

pushing up the cost of electricity in other western states as well.

Before Restructuring

California's electricity market is part of a larger, interconnected electricity grid called

the Western Interconnect. The Interconnect comprises 11 western states (as well as

parts of western Canada and northern Mexico) that effectively constitute one large

market for electricity. What happens to supply or demand in one part of the region

will influence prices in the other parts. For example, changes in the capacity to

generate hydroelectric power—the cheapest source of electricity—in Washington

Various Electric Utilities 

in California That

Generate Power

• Investor-owned

utilities

• Municipal utilities

Other Power Producers

in California

• Independent

producers

• Qualifying facilitiesc

Federal Utilities 

• Bonneville Power

Administration

• Western Area Power

Administration

Utilities in Other States

Various Electric Utilities

in California That

Distribute Power

• Investor-owned

utilities

• Municipal utilities

• Cooperative utilities

Wholesale Brokers 

California Department

of Water Resources

Homes

Businesses

Government
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 3

3. Energy Information Administration, Electric Power Annual 1996, vol. 1, DOE/EIA-0348(96)/1 (August

1997), Tables 9 and 23, and Electric Power Annual 1996, vol. 2, DOE/EIA-0348(96)/2 (February 1998),

Table 63.

4. Energy Information Administration, Electric Power Annual 1996, vol. 2, Table 6.

5. Transmission is the movement of power over high-voltage lines from generators to local utilities. Local

distribution systems then carry that power over low-voltage lines to households and businesses. Before

restructuring, San Diego Gas and Electric had the lowest level of vertical integration of the three large

utilities. It purchased about half of the power that it sold (rather than generating that power itself).

State can affect the supply of electricity available to all power-importing states in the

Interconnect.

California is a net importer of power from its neighbors. In 1996, the state's

utilities sold about 20 percent more electricity to their customers than was generated

by local plants.3

 Typically, however, the state’s utilities and independent power producers also sell to other states, and in certain seasons, the net flow of power is out of

California.

For years, electricity prices were much higher in California than in neighboring

states. In 1996, the average price to California households and businesses was 9.5

cents per kilowatt hour (kWh)—75 percent more than the average price in the 10

other western states.4 A big part of that difference resulted from the greater availability of cheap hydropower in other parts of the West. California’s policymakers

could not alter the allocation of western hydropower, which depends on nature (the

location of rivers) and federal policy (regional preferences in the sale of federal

hydropower). But they could address two other factors that caused high prices: the

structure of California’s market (regulated monopolies) and state policies to support

alternative energy. The fact that the state’s utilities were facing increasing market

pressure from independent power producers gave policymakers an extra impetus to

do something about high prices.

Inefficiencies of Regulated Monopolies. Before restructuring, California's electricity

was supplied by a mixture of large private utilities (owned by investors) and municipal

power companies (owned by cities and counties). About 70 percent of Californians

were customers of the state’s three large investor-owned utilities.

To varying degrees, those utilities were vertically integrated, meaning that they

were involved in all phases of their industry, controlling much of the generation, transmission, and distribution of electricity in their respective service areas.5

 They also

functioned as regulated monopolies, meaning that each was the only utility that could

operate in its service area, though with certain restrictions. The state's Public Utility

Commission (PUC) approved the retail prices that those private utilities could charge

for electricity and oversaw the reliability of their service. The Federal Energy Regu-
4 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

6. Energy Information Administration, Renewable Energy 1998: Issues and Trends, DOE/EIA-0628(98)

(March 1999), Table 9.

7. Energy Information Administration, Renewable Energy 2000: Issues and Trends, DOE/EIA-0628(2000)

(February 2001), Table 6.

latory Commission (FERC) was responsible for approving the wholesale prices that

electricity producers could charge utilities for power and the rates that utilities could

charge for the use of their transmission lines.

Under traditional regulation, the private utilities were allowed to charge prices

that recovered their costs of production and gave investors a large enough return to

attract ample capital for the utilities. Economists have long pointed out that such

regulation encouraged utilities to overinvest in electricity-generating capacity because

the cost of additional capacity could be more than covered by higher electricity prices.

Indeed, in the mid-1990s, California’s private utilities had much more generating

capacity than they needed to supply their customers.

The Cost of Supporting Renewable Energy and Cogeneration. Another factor that

contributed to high electricity prices in California before restructuring was federal and

state policies that ordered utilities to buy electricity generated from alternative energy

sources. The federal Public Utilities Regulatory Policy Act of 1978 required utilities

to purchase all of the power generated by smaller producers known as qualifying facilities. Those producers generate electricity from renewable sources of energy (such

as wind power) or as a by-product of manufacturing (a process called cogeneration).

The 1978 law let the individual states set the prices that the utilities would pay for

power generated from those sources.

Initially, California’s PUC decided that the price for power from qualifying facilities should reflect the cost of the most expensive source of electricity—nuclear

power. That decision was a boon to renewable-energy producers and cogenerators

in the state, who could produce electricity much more cheaply than that. In 1995 (the

last year for which data are available), California utilities paid an average of 12.3 cents

per kWh for electricity from qualifying facilities, compared with only 4.2 cents per

kWh for power from other sources.6

 As a result, electricity from qualifying facilities

grew from less than 1 percent of the state's total generation in 1980 to about 20

percent in 1996.7

 That increasing reliance on alternative energy sources pushed up

the average cost of power for utilities. But because regulators allowed the utilities to

pass along the full cost of that power, their customers ended up bearing the brunt of

the higher costs.

Competition from Independent Power Producers. California’s large private utilities

had little incentive to try to reduce their high costs so long as their customers (both

retail customers and the municipal and cooperative utilities that purchased wholesale
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 5

8. For a discussion of stranded costs, see Congressional Budget Office, Electric Utilities: Deregulation

and Stranded Costs, CBO Paper (October 1998).

9. Growing competition also threatened the utilities’ ability to continue supporting state programs to

promote energy conservation and renewable energy without raising prices for their remaining customers.

Those programs include demand-side management (such as paying consumers to invest in efficient

appliances), public benefit funds (which charge retail customers extra to pay for subsidies to renewableenergy producers), and renewable portfolio standards (which require utilities to supply a minimum

percentage of their power from renewable sources).

power from them) had little ability to choose other suppliers. Much of the momentum to restructure California’s electricity market resulted from federal policies that

supported the emergence of an independent power industry and gave the utilities’

wholesale customers greater flexibility to shop for lower-cost supplies. Retail customers in the industrial sector also put pressure on the utilities because they had

increasing incentives to switch to natural gas (and generate their own electricity) or

relocate to regions with lower electricity prices.

One of the most important changes in federal policy was the Energy Policy Act

of 1992, which encouraged the entry of new independent producers into electricity

markets around the nation. Those independent firms increasingly sold power directly

to municipal and cooperative utilities and worked with large industrial customers to

develop cogeneration capabilities, which permitted those customers to supply part of

their own power needs and sell excess power to the utilities. (Independent producers

—many of which generate electricity from natural gas—and small producers that use

renewable energy or cogeneration are known collectively as nonutilities; they are not

generally subject to price regulations or universal-service requirements.) The 1992

federal law also provided incentives for utilities to spin off affiliated but unregulated

independent power businesses. In addition, it gave independent producers open

access to the utilities’ transmission systems. 

Before independents entered the market, California utilities had not faced competition. The utilities' high costs of generating power, as well as the costs of their

long-term contracts with qualifying facilities, could be passed on to customers without

financial harm to themselves. As competition spread, however, those generating

plants and contracts increasingly became liabilities for the utilities; they eventually

became known as stranded costs.8

 The utilities could not recoup those costs in a

competitive market, where prices were expected to fall, unless regulators took some

action, such as setting a floor for retail prices. Most of the potential stranded costs

of California utilities resulted from long-term supply contracts. Any loss of wholesale

customers or large retail customers to independent producers raised the prospect that

the utilities’ remaining customers would face even higher prices.9
6 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

10. Energy Information Administration, Electric Sales and Revenue 1999, DOE/EIA-0540(99) (October

2000), Table 17.

The Restructuring Plan of 1996

Beginning in 1994, the California Public Utility Commission proposed a number of

regulatory changes to the electricity market. Those changes—together with public

law AB 1890, enacted in 1996—define the major elements of California's restructuring plan.

• The three large investor-owned utilities were required to divest themselves of at least half of their fossil-fuel-powered generating plants.

(Fossil fuel includes natural gas, coal, and oil, but in California most of the

fossil-fuel plants burn natural gas.)

• A nonprofit corporation, the Power Exchange (PX), was created to run

wholesale electricity auctions, where the utilities were required to buy all

of their power that was not coming from their own plants or from preexisting contracts (primarily with qualifying facilities). That requirement

effectively precluded the utilities from entering into long-term contracts

with independent power producers because, until 1999, the PX did not

sell such contracts.

• The utilities were also required to transfer control (though not ownership)

of their transmission networks to another nonprofit corporation, the California Independent System Operator (CAISO).

• The restructuring plan froze retail prices for electricity until 2002 (or such

time as the utilities recovered certain stranded costs). 

• Finally, consumers were given a choice of continuing to buy power from

their traditional utility or purchasing it from other suppliers—with the new

supplier delivering power over the utility’s distribution system and consumers being billed separately for power and distribution services. (Although many people believed that consumer choice was among the plan’s

most significant features, few customers actually switched suppliers while

prices remained frozen.)

Sale of Generating Capacity. To promote wholesale competition among power

generators, the plan required the state’s three large private utilities to sell half of their

fossil-fuel-powered generating capacity.10 In the end, the utilities sold all of that

capacity, although they kept virtually all of their hydropower and nuclear assets. The

utilities also retained their long-term supply contracts with qualifying facilities,
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 7

11. Data from the Energy Information Administration on existing capacity and planned additions to capacity

for electric utilities and nonutilities are available at www.eia.doe.gov. In both 1999 and 2000, the rest

of the market’s electricity came from power generators in other states, including federally owned sources

(such as the Bonneville Power Administration), and from municipal utilities in California. Much of that

additional supply was generated from hydropower. 

although the plan gave them the resources to renegotiate the onerous pricing provisions of those contracts.

By September 2000, the effects of the required divestiture of generating assets

were clearly visible. Power plants owned by the utilities provided just 28 percent of

the electricity in the state's restructured power market, down from 40 percent the

previous year. Meanwhile, the share from nonutilities in the state (independent power

generators, including qualifying facilities) reached 58 percent, up from 40 percent in

1999.11

With that shift, the nonutilities assumed a more important role in determining

prices in the new market. Under the plan’s rules for wholesale auctions, wholesale

electricity prices in the restructured market (like prices in other competitive markets)

would be determined by the marginal cost—that is, the cost of the last and most

expensive unit produced. Since divestiture, the utilities have generated their own

electricity only from hydropower and nuclear power facilities. They usually operate

those facilities to meet their base load requirements (the base level of their customers’

demand for power, not counting daily and seasonal peaks in use) because of those

facilities’ low variable costs. The nonutilities, by contrast, generate most of their

power from natural-gas-fired plants. Those plants also supply power for base load

requirements, but they are especially important in meeting the increased requirements

of peak periods. Thus, the contribution from gas-fired plants is critical in extreme

market conditions such as those of 2000 and 2001, when demand rose to record levels

and the utilities’ supply from hydropower dropped. In those circumstances, the

market price of electricity depends directly on the level of natural gas prices and the

efficiency of operating gas-fired plants.

The Power Exchange. Most of the wholesale exchange of electricity between independent producers and the investor-owned utilities took place in a new market, under

the aegis of the PX. Those utilities were required to buy power in that market. From

1998 until its termination in January 2001, the PX ran several different auctions,

matching supply and demand and setting prices. Sellers submitted bids in the form of

a supply schedule (how much they would supply at various prices), and buyers

submitted bids in the form of a demand schedule (how much they would buy at

various prices).

Initially, the PX conducted auctions only for power to be dispatched in each

hour of the next day (the day-ahead market). Later, it added a block-forward market,
8 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

which allowed bids for blocks of hours for each day of the month, for one to six

months in the future. In both types of auctions, the lowest-bid supplies were awarded

first, but the price paid for all supplies was based on the last and most expensive unit

of power sold (the marginal cost of supply in the market at that time).

The PX was shut down in January 2001 after its two largest customers, Pacific

Gas and Electric and Southern California Edison, defaulted on payments for power

they had purchased through the PX. At that time, sellers stopped offering electricity

in PX auctions for fear of not being paid, and the exchange suspended participation

by the two utilities. Much of the business formerly conducted through the PX moved

to the CAISO or was replaced by direct contracts with the state government.

The California Independent System Operator. The plan’s other new institution, the

CAISO, took over the task of coordinating supply and demand in the state’s

electricity transmission system—a job that had formerly been done by the private

utilities that owned the transmission lines. Electricity transmission requires the continuous balance of power supply with consumer use (or load): too much or not enough

power at any moment can crash the entire system. The vertically integrated utilities

that owned the lines had managed that balancing task. But with open access to transmission lines, there was concern that the utilities would give preference in scheduling

to power from their own generators. A primary goal for the CAISO was to ensure

nondiscriminatory access.

Besides scheduling power supplies from various sources for the next day (consistent with projections of next-day demand), the CAISO is responsible for acquiring

access to additional supplies to meet unanticipated surges in demand or losses of

generation. To that end, the CAISO operates a real-time market—an auction for

acquiring power supplies in the next hour, separate from the auctions formerly run by

the PX. (That real-time auction enables the CAISO to buy what the restructuring

plan expected would be the small amounts of power necessary to balance the system.)

To ensure adequate reserves and avoid the need for last-minute purchases, the CAISO

conducts another auction for the provision of standby capacity. It can also forgo its

auctions altogether by contracting with suppliers bilaterally in so-called out-of-market

purchases. The CAISO then bills the utilities that distribute the electricity for its purchases on their behalf.

As carried out by the Public Utility Commission, the restructuring plan limited

the ability of utilities to make long-term deals with independent power producers

(other than qualifying facilities) by requiring them to buy all of the power they needed

but did not generate themselves in the PX and CAISO markets. The restriction on

long-term contracting effectively prohibited the utilities from participating in futures

markets for electricity. That restriction, which was formulated as part of the 1996

plan, was eased somewhat in later actions. In 1999, the PX added the block-forward
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 9

12. To make it easier for utilities to renegotiate contracts with qualifying facilities, the restructuring plan

gave utilities the right to receive a stream of income from ratepayers—paid as a special surcharge on

customers’ power bills. In a process known as securitization, the utilities turned that right over to a

state infrastructure bank in exchange for a cash payment. The state infrastructure bank then issued

bonds that are backed by that stream of income. Unlike the case with debt that the utilities could issue

themselves, income from those bonds is exempt from state taxes.

13. Following the lead of deregulation in natural gas and telephone service, the owners of the distribution

network (which still held a monopoly) were allowed to charge a distribution fee for delivering power

to those customers. The fee could include charges for other services and for state programs.

market to let utilities buy hourly blocks of power one to six months in advance. And

in 2000, the PUC eased the limits on bilateral long-term contracts and futures trading.

One reason that California’s restructuring plan restricted long-term contracts

was to help ensure a competitive wholesale market by forcing a large share of power

sales into the new PX and CAISO auctions. The plan’s framers feared that if such

contract arrangements were allowed, they would let the utilities maintain some degree

of vertical control over independent producers and effectively thwart the goal of

divestiture.

Retail Price Freeze. The plan mandated a reduction and freeze in the retail price of

electricity. That provision had two goals. One was to allay consumers’ fears that

restructuring would force them to pay higher prices. The other was to assure the

utilities that retail prices would not drop too much relative to wholesale prices, so

they would be able to pay off their stranded costs. Accordingly, prices were supposed

to be frozen at a level 10 percent below the 1996 level. The freeze was to last until

2002 or until the utilities had paid off their stranded costs—whichever came first.

As it turned out, however, the reduction in prices for consumers was close to

zero because the state effectively loaned the utilities the present value of the 10 percent reduction for their immediate use in paying off stranded costs and then required

them to repay that loan from a surcharge on customers’ bills.12 The remaining funds

to repay stranded costs were to come from the utilities’ sales of fossil-fuel-powered

generating plants and from the difference between the retail price and the wholesale

price that would be set in the new competitive marketplace. 

Consumer Choice. Finally, to help ensure that electricity users would ultimately see

the benefits of lower wholesale prices, consumers were immediately given the option

to purchase their power directly from a retailing generator (or reselling middleman)

of their choosing or to continue buying it from the utility that distributes the power.13

Framers of the plan expected that when the plan was fully implemented (by 2002 at

the latest), the retail price of electricity would reflect the wholesale price—what it

cost for whichever producer customers had selected as their power source to generate
10 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

14. See Bureau of Economic Analysis, “Regional Accounts Data,” available at www.bea.doc.gov/bea/

regional/data.htm. Real annual growth in 2000 was estimated by the Congressional Budget Office using

BEA data for income and deflators for gross state product.

electricity. However, very few customers exercised their option to sign up with new

suppliers until California directed the utilities to raise retail prices in March 2001.

Market Developments from 1996 Through 2001

California’s electricity crisis was precipitated by a convergence of long-term trends

and special circumstances that created a scarcity of power and put upward pressure

on electricity prices, not just in California but throughout the West. Several events

are especially important to understanding the stress on electricity markets in the

region. Strong economic growth in California and extreme weather throughout the

West in the summer of 2000 pushed the demand for electricity to record levels. The

excess generating capacity of the early 1990s had almost disappeared by that time,

especially for peaking capacity (the generating capacity needed to meet the demand

for electricity when it is highest). The amount of water flow in streams used to

generate hydropower fell in 2000 from the high levels of 1999. And natural gas prices

increased sharply, making it difficult to use gas to meet the increased demand for

electricity or to replace hydropower without raising prices. In those tight market

conditions, some characteristics of California’s restructuring plan caused wholesale

prices to rise well above what they might have been under the old regulated system

or under a better restructuring plan.

Growth in Demand for Power Because of Economic Expansion. Increases in electricity consumption track increases in real (inflation-adjusted) personal income. In

California, real personal income grew at an annual rate of 3.2 percent from 1994

through 1998, with a corresponding increase in electricity consumption of 1.5 percent

a year.14 In 2000, however, personal income in California grew by 9.3 percent, which

contributed to a surge in demand for electricity (see Figure 2). That unexpected jump

in demand put substantial upward pressure on prices.

Under normal circumstances, neighboring states in the Western Interconnect

might have responded by selling more power to California utilities, which might have

lessened the effect of strong demand on electricity prices. But their capacity to sell

to California was strained as well. Those states had to accommodate their own

growth in electricity consumption. For example, between 1994 and 1998, Arizona's

electricity use grew by 3.8 percent a year, and Nevada's grew by 6.5 percent a year,

rates much higher than the 1.5 percent annual growth that California experienced

during those years.
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 11

15. California Energy Commission, High Temperatures & Electricity Demand—An Assessment of Supply

Adequacy in California: Trends & Outlook (Sacramento: California Energy Commission, July 1999).

1985 1988 1991 1994 1997 2000

0

50

100

150

200

250

300

 Billions of Kilowatt Hours per Year

FIGURE 2. ELECTRICITY CONSUMPTION IN CALIFORNIA, 1985-2000

SOURCE: Congressional Budget Office based on data from Energy Information Administration, Electric Power Annual, 

vol. 1, DOE/EIA-0348/1 (various issues), Table A21.

Extreme Temperatures in Western States. Electricity consumption is also highly

dependent on local weather conditions, which affect the demand for cooling in the

summer and heating in the winter. For example, the California Energy Commission

estimates that if summer temperatures are 5 degrees Fahrenheit higher than normal,

California’s electricity demand rises by 8.5 percent.15 In a broad region such as that

covered by the Western Interconnect, usually when one area is having extreme

weather, such as sustained high temperatures, other areas will be experiencing moderate weather. As a result, regional demand for electricity tends to be more stable

than local demand. Across the far western states, utilities have traditionally counted

on a pattern of peak demand during the winter in the north (Oregon and Washington)

and peak demand during the summer in the south (California, Arizona, and Nevada).

When unusually high or low temperatures occur throughout a broad area,

however, demand for electricity in the region can rise significantly. In the summer of
12 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

1998, such a coincidence of high temperatures occurred in California and the Southwest. As a result, California several times declared Stage 2 alerts, which authorized

the disruption of interruptible service (service for those customers who pay less in exchange for being cut off in times of shortage). Those weather conditions represented

the most extreme coincidence of regional temperatures since 1985 and were thought

to be an isolated occurrence. But in the summer of 2000, they happened again, as

temperatures stayed high for several periods all across California, Arizona, and New

Mexico. Demand for electricity in California was 14 percent greater that summer than

in the summer of 1999. Moreover, California’s neighbors (which otherwise could

have sent excess supply to the state) were experiencing high demand, too.

Weather conditions also had a constricting effect on the supply of power. The

far northwestern states experienced earlier-than-normal winter temperatures in the fall

of 2000, so little transition existed between summer and winter demand peaks for the

entire western region. Because of that short transition, independent producers that

had run aging gas-fueled generators at high capacity through the summer were not

able to service those units fully during the normal autumn downtime. The result was

added maintenance problems with natural gas facilities during the winter months. 

Problems with Generating Capacity. The large, unexpected increase in electricity

demand in 2000 came at an especially bad time, for two reasons. First, construction

of generating capacity in the West had not kept pace with the long-term growth of

demand. And second, unusually high levels of existing capacity in California—at

times, nearly 10 percent of the state’s generating capacity—were idle for maintenance

and other reasons.

Between 1995 and 1999, generating capacity in the West remained essentially

the same. Data from the Energy Information Administration on capacity at the region's electric utilities and nonutilities present a combined picture of the stagnation in

capacity in the West (see Table 1).

When the restructuring debate began in California, the state had a large and

costly reserve of generating capacity. But the state’s early concern that high capacity

led to high year-round prices, plus local opposition to new generating plants and an

uncertain investment climate, contributed to a halt in construction of new facilities.

(Uncertainty about market restructuring was probably not a major cause of that halt,

since a similar lack of investment activity existed in surrounding states that did not

restructure.) As California’s reserve margin for electricity generation diminished in

the late 1990s, it became more and more costly to boost local production to meet

short-term increases in demand.

Besides limited capacity, the poor physical condition of existing generators

heightened the western states’ vulnerability to a severe market disruption in the face

of higher demand in 2000. The California Energy Commission reported that in 1999,
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 13

16. Ibid.

17. Federal Energy Regulatory Commission, Staff Report to the Federal Energy Regulatory Commission

on Western Markets and the Causes of the Summer 2000 Price Abnormalities, Part I (November 1,

2000), Figure 2-12.

18. Federal Energy Regulatory Commission, Report on Plant Outages in the State of California (February 1,

2001), Figure 2.

TABLE 1. ELECTRICITY-GENERATING CAPACITY IN THE WESTERN STATES,

1995–1999 (In megawatts)

1995 1996 1997 1998 1999

Electric Utilities (WSCC) 129,751 131,292 129,232 116,159 107,832

Nonutilities (Mountain and

Pacific) 16,617 17,408 16,985 29,672 40,096

Total 146,368 148,700 146,217 145,831 147,928

SOURCE: Energy Information Administration, Electric Power Annual 1999, vol. 2, DOE/EIA-0348(99)/2 (October 2000),

Tables 34 and 53.

NOTE: WSCC is the Western Systems Coordinating Council region (excluding Canada and Mexico) of the North American

Electric Reliability Council. Nonutilities are independent electricity producers as well as some small producers (known

as qualifying facilities) that use renewable energy sources or cogeneration to produce electricity. Mountain and Pacific

are regions of the Census Bureau; figures for those regions include small amounts of generating capacity in Hawaii and

Alaska.

about 60 percent of the state’s oil- and gas-fired generating units—capacity that was

critical for meeting peak-period demand—were at least 30 years old.16 In part because of the maintenance demands of older equipment, a larger-than-usual share of

the existing capacity in California was idle at the outset of the summer 2000 crisis.17

Planned outages in April 2000 idled about 8,800 megawatts of capacity—nearly a

fifth of the state's total. All but about 1,000 megawatts of that capacity came back

on line in the next few months, but unplanned outages grew over the summer, reaching about 3,400 megawatts by August. During the subsequent winter crisis, unplanned outages in the state hovered around 4,000 megawatts, or about 10 percent

of total generating capacity.18

The consequences of strong growth in demand, little growth in capacity, and

idled generators show up in data on peak reserve margins. Traditionally, utilities have

tried to maintain a large enough reserve of untapped capacity to meet peak-period
14 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

19. Reserve requirements are set by the North American Electric Reliability Council. Membership in the

council is voluntary.

20. California Energy Commission, High Temperatures & Electricity Demand, Table III-1.

21. Energy Information Administration, Electric Power Monthly, DOE/EIA-0226 (various issues), Tables

45 and 47. Although the North American Electric Reliability Council, which includes California utilities, does not require members to maintain a reserve margin (which includes allowances for scheduled

maintenance and forced outages), it does require an operating margin of 5 percent to 7 percent, which

could translate into a 15 percent reserve margin.

demand (both seasonal and daily peaks).19 With growing demand and idled capacity,

peak reserve margins in California and the western region were already at historical

lows before the summer of 2000.20 In 1997 (the last year reported), the reserve margin in California and southern Nevada was only 7.8 percent, down from 14.3 percent

in 1995 (just before California’s restructuring plan was enacted). Those estimates are

based on regional demand levels that do not assume a coincidence of extreme weather

across states, such as occurred in 1998 and again in the summer of 2000.21 As a

result, they probably overestimate the actual ability of the western power market to

meet demand in such circumstances. Since then, reserve margins have continued to

shrink.

Problems with Hydropower Supplies and Natural Gas Prices. Electricity supplies in

the West in the summer of 2000 were constrained and increasingly expensive because

of several interrelated factors involving the supply of hydropower and the price of

natural gas. Stream flows returned to normal levels in the western coastal states

(from the high levels of 1999) and dropped below normal levels in the mountain

states, reducing the region’s capacity to generate electricity from hydropower. (In

effect, the West had benefited from conditions that were especially favorable to

hydropower in 1999, which had masked the problems of California’s restructuring

plan.) That reduction in hydropower forced the region to rely on more costly sources

of electricity, particularly natural-gas-powered facilities owned by independent generators. At the same time, natural gas prices across the country began to climb toward

record levels.

In 1999, the California Energy Commission estimated that the western states

had just enough reserve generating capacity to accommodate another summer like

that of 1998. In other words, regional demand could be met by fully utilizing all

available capacity, assuming that stream levels across the West were, on average, at

normal levels. That estimate also assumed that utilities would need to restrict sales

to some customers with interruptible service, as they had in 1998. But in 2000,

electricity generation from hydropower was lower across the western states than it

had been in 1998, so noninterruptible service was threatened, too. In California, net

generation from hydropower in 2000 dropped 13 percent from the above-normal level
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 15

22. Data for 1999 and the first 10 months of 2000 come from Energy Information Administration, Electric

Power Monthly, DOE/EIA-0226(2001/01) (January 2001), Table 11.

23. An increase of $1 per thousand cubic feet in the price of natural gas translates into an increase of $20

per megawatt hour in the cost of producing electricity; see Federal Energy Regulatory Commission,

“Notice of Proxy Price for February Wholesale Transactions in the California Wholesale Electric

Market,” Docket No. EL00-95-018, available at www.ferc.gov/electric/bulkpower/feb_proxy.PDF.

TABLE 2. NET ELECTRICITY GENERATION FROM HYDROPOWER AND NATURAL

GAS IN 11 WESTERN STATES, FIRST NINE MONTHS OF 1999 AND 2000

(In millions of kilowatt hours)

Hydropower Natural Gas

1999 2000 1999 2000

Electric Utilities 154,020 126,955 29,846 35,995

Nonutilities 3,130 5,231 69,365 102,510

Total 157,150 132,186 99,211 138,505

SOURCE: Energy Information Administration, Electric Power Monthly, DOE/EIA-0226(2001/01) (January 2001), Tables 10

and 65.

NOTE: Nonutilities are independent electricity producers as well as some small producers (known as qualifying facilities) that

use renewable energy sources or cogeneration to produce electricity.

of 1999.22 For the other western states, total hydropower production fell by 18 percent in 2000. In particular, Washington, Oregon, and Idaho—which the previous year

had depended on hydropower for about 85 percent of their electricity generation (and

had sent much of that power to California)—had to replace that low-cost energy with

electricity from more expensive sources.

That loss of supply from inside and outside California put further upward pressure on electricity prices in the state and the region. As the demand for electricity

increased relative to the supply in the summer of 2000, the western market turned

increasingly to producers with natural-gas-fired generating plants (see Table 2). At

the same time, the high cost of producing electricity from natural gas became greater

still. The prices that electricity producers paid for natural gas had remained fairly

stable—in the range of $2 to $3 per thousand cubic feet (mcf)—since the wholesale

gas market was deregulated in 1986. Starting in April 2000, however, those prices

rose significantly above $3 per mcf, reaching $4.90 per mcf by August (see Figure

3).23
16 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

24. Energy Information Administration, Natural Gas Monthly, DOE/EIA-0130(2001/06) (June 2001), Table

20.

Jan. 1999 July 1999 Jan. 2000 July 2000

0

5

10

15

20

 Dollars per Thousand Cubic Feet

FIGURE 3. PRICES THAT CALIFORNIA UTILITIES PAID FOR NATURAL GAS,

JANUARY 1999 THROUGH DECEMBER 2000

SOURCE: Congressional Budget Office based on data from Energy Information Administration, Natural Gas Monthly,

DOE/EIA-0130 (various issues), Table 24.

The increase in natural gas prices was itself related to developments in the

electricity market. Natural gas exploration and development lagged in the past decade

because of relatively low prices for oil and gas, which meant that there was little

excess capacity to absorb the increase in demand for gas in 2000 that resulted from

the demand for electricity. Thus, that higher electricity demand most likely played a

role in raising natural gas prices. Support for that view comes from the fact that

prices paid for natural gas at the wellhead did not start increasing until June 2000,

whereas prices for gas delivered to utilities were already rising two months earlier.

Some observers contend that gas marketers actively restrained the supply of natural

gas to California in order to push up prices. Evidence for such actions is not apparent, however—the average monthly prices that local distribution companies in the

state paid for gas in the past year were not significantly out of line with prices in highcost cities in the Northeast and the South.24
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 17

25. The goal of the NOx credit program is to minimize the total cost of attaining a national standard for NOx

emissions. It requires the operator of a fossil-fuel-fired plant that emits NOx in excess of the standard

to purchase credits from other operators that generate extra credits by emitting NOx in an amount below

the standard. For more information about the NOx program, see Congressional Budget Office, Federalism and Environmental Protection: Case Studies for Drinking Water and Ground-Level Ozone (November 1997), and Factors Affecting the Relative Success of EPA’s NOx Cap-and-Trade Program, CBO

Paper (June 1998).

26. Federal Energy Regulatory Commission, Staff Report to the Federal Energy Regulatory Commission

on Western Markets, Part I.

Another factor that made supplying electricity from natural gas even more costly

was the environmental controls that California adopted to carry out the federal Clean

Air Act and its amendments. In particular, electricity producers and other industries

in California that burn fossil fuels are required to hold credits for the right to emit

nitrogen oxides (NOx), a by-product of fossil-fuel combustion.25 Buying NOx credits

represents a cost to producers who exceed the legal standard for NOx emissions,

generally reflecting their avoided cost of acquiring cleaner fuels or investing in technology to reduce emissions. The increased use of natural gas in mid-2000 meant that

more credits had to be purchased. As a result, the price of the credits leaped from

$4,000 per ton of emissions to more than $45,000 per ton during that year. For a

natural-gas-fired turbine that emits two pounds of NOx for each megawatt hour

(mWh) of electricity it generates, credit prices at that level add about $45 per mWh

to the cost of electricity.26

Cumulative Effects. By early 2001, California's restructuring plan was seen by virtually all observers as a failure. The rolling blackouts that occurred during the first

few months of the year provided dramatic evidence of that failure—as did the soaring

wholesale prices for electricity and the worsening financial condition of the large

utilities that were subject to the plan. The prices that utilities paid for power to supply

both the southern and northern California markets had generally been below $40 per

mWh in the spring of 1998. Two years later those prices started rising dramatically,

reaching a monthly average of more than $250 per mWh by the end of 2000 (see

Figure 4). Although a precise total is difficult to determine, the press frequently

reported that between the onset of the crisis and the first quarter of 2001, the three

utilities lost a total of $12 billion to $14 billion. In April, Pacific Gas and Electric

declared bankruptcy, claiming debts of $8.9 billion. 

WHAT ROLE DID THE RESTRUCTURING PLAN PLAY?

When California’s plan was enacted, the expectation of falling or (at worst) stable

wholesale prices was the political glue that held together the conflicting interests who

formulated and agreed to the plan. However, aspects of that plan—combined with
18 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

Apr. 1998 Oct. 1998 Apr. 1999 Oct. 1999 Apr. 2000 Oct. 2000

0

50

100

150

200

250

300

 Dollars per Megawatt Hour

FIGURE 4. AVERAGE PRICES THAT UTILITIES PAID FOR ELECTRICITY IN

THE CALIFORNIA POWER EXCHANGE’S DAY-AHEAD AUCTIONS, 

APRIL 1998 THROUGH DECEMBER 2000

SOURCE: Congressional Budget Office based on data for the northern and southern regions from the California Energy Commission (available at www.energy.ca.gov/electricity/wepr/monthly_day_ahead_prices.html).

limits on electricity supplies within the state and the rest of the West that were beyond

the reach of the plan—amplified upward pressures on wholesale prices.

Analysts point to three features of the restructuring plan that go a long way in

explaining how the stresses of extreme market conditions in the summer of 2000

pushed California’s utilities into debt and led to supply disruptions in the state. Those

features are the freeze on retail prices, the restriction on long-term contracts, and the

design of the PX and CAISO markets. The first two features created a financial disaster for the investor-owned utilities when wholesale electricity prices began to rise.

The third feature exacerbated those financial problems by letting independent pro-
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 19

27. As noted earlier, the freeze was intended to last until the three large investor-owned utilities recovered

their stranded costs or until 2002 (whichever came first). In the summer of 2000, the freeze still applied

to customers of two utilities, Pacific Gas and Electric and Southern California Edison. The freeze for

customers of San Diego Gas and Electric had been lifted on July 1, 1999 (although it was reimposed

later).

28. Brownouts involve decreasing the level of power supplied to customers (reducing the voltage); blackouts

involve turning off power completely.

ducers avoid limits on wholesale prices and, perhaps, by enabling them to exercise

their market power to raise prices even further. However, the restructuring plan did

not and could not alter all of the western power market, much of which remained

regulated by other states and the federal government.

The Price Freeze

Initially, the freeze on the price that retail customers could be charged for electricity

acted as a price floor. The idea was that if wholesale prices fell (which they were

expected to do), retail prices would not fall along with them. That would help maintain the utilities’ cash flows, although it would also keep consumers from enjoying the

benefits of competition at the wholesale level. In the summer of 2000, however,

wholesale prices rose above the fixed retail price for a sustained period. When that

happened, the freeze acted as a price ceiling: utilities could not pass on their rising

costs to consumers.27

Not allowing retail prices to change with conditions in the wholesale market had

three important effects. First, and critically, when wholesale prices rose, net cash

flows for the investor-owned utilities fell, which made it impossible for them to continue distributing electricity profitably. Instead, they had to sell at a loss. Even though

the utilities are required to meet all of their customers’ needs for power, their financial

difficulties have forced them to curtail service on several occasions (through brownouts and blackouts).28 Second, the price freeze probably discouraged new retail sellers from entering the market. Third, the freeze diminished whatever incentive retail

customers would otherwise have had to reduce their electricity use. Such a reduction

could have helped dampen some of the upward pressure on wholesale prices.

Financial Problems for Utilities. The price freeze affected the wholesale market for

electricity in ways that hurt the investor-owned utilities. As the financial condition of

those utilities deteriorated (from having to operate at a loss), some producers demanded higher prices to sell power to the utilities to compensate for the risk that they

would not get paid. Those fears proved to be realistic; the utilities stopped payments

to the CAISO and to small independent generators or cogenerators of electricity.

Some generators, such as those producing electricity from hydroelectric facilities,

reportedly refused to sell to California utilities at any price until credit concerns could
20 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

29. The U.S. Secretary of Energy (first William Richardson and then Spencer Abraham) has required

generators to sell to the California market. The Secretary derives the authority to do that from section

202(c) of the Federal Power Act. If California utilities are ultimately unable to pay for electricity that

the federal government requires generators to sell to them, it is unclear who will be responsible for those

losses.

30. The U.S. Secretary of Energy has required natural gas suppliers to deliver to Pacific Gas and Electric.

The Secretary derives the authority to do that from section 302 of the Natural Gas Policy Act and section

101(c) of the Defense Production Act.

31. James Bushnell and Erin Mansur, The Impact of Retail Rate Deregulation on Electricity Consumption

in San Diego, Working Paper PWP-082 (Berkeley, Calif.: University of California Energy Institute,

Program on Workable Energy Regulation, April 2001), available at www.ucei.berkeley.edu/ucei/PDF/

pwp082.pdf.

be resolved.29 (Their reluctance was part of what prompted the state to assume responsibility for purchasing power on its own.) In addition, the large California utilities operate distribution systems for natural gas, and the severe fall in their electricity

earnings jeopardized their ability to buy natural gas for resale to independent power

generators.30

Fewer Retail Sellers. More subtly, the price freeze probably also discouraged some

generators and marketers of electricity from selling power directly to retail customers

in California. If the price faced by consumers who stayed with their traditional utility

had tracked the wholesale price of power (even with various surcharges) rather than

being frozen, the resulting variation in prices would have left room for retailers to

offer fixed-price contracts to attract risk-averse consumers. Those alternative retailers would have been free to sign long-term contracts with suppliers or engage in other

hedging activities to minimize the risk they faced in offering fixed prices to their

customers—activities that the restructuring plan did not allow California’s private

utilities to pursue.

Little Incentive for Conservation. The retail price freeze also diminished the incentives for consumers to conserve electricity. The ability of consumers to greatly reduce

electricity use on short notice is small relative to their total consumption. But relative

to the size of the power disruptions that California has experienced so far, the ability

to conserve could be significant. Reserve margins of less than 1.5 percent will trigger

rolling blackouts; in the blackouts of March 2001, about 5 percent of California’s

households and businesses experienced a loss of service, which lasted for less than

two hours. Even a very small percentage reduction in consumption could have helped

avert such interruptions of service.

In San Diego, where retail customers briefly faced market prices in the summer

of 2000, evidence suggests that higher prices caused a decline in power use. A

doubling of retail prices led to a drop in demand of between 2.2 percent and 7.6

percent, depending on the hour of the day.31 By September 2000, legislators had
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 21

32. The PX requested and was granted authority by the Federal Energy Regulatory Commission in several

instances to offer forward contracts, including contracts for the block-forward market. Later, the PUC

permitted the investor-owned utilities to participate in those new PX markets, although it limited the

amount of power they could buy for future delivery. The PUC also reserved the right to review

contracted prices for future reasonableness, so those new contracts did not effectively help the utilities

guarantee a price for future delivery.

responded to public pressure by reducing and refreezing retail prices in San Diego, so

customers there had no further incentive to curb their demand for electricity. Indeed,

the opposite may have occurred, since consumers increased their use when prices

dropped.

Although consumers’ ability to reduce power consumption in response to higher

prices is limited in the short term, it increases in the longer term. When they are faced

with the full cost of electricity, residential customers have an incentive to buy energysaving appliances, add insulation to their homes, or switch from electric to gas-fired

appliances. Industrial customers can not only purchase energy-efficient equipment but

also add their own power-generating facilities or even cogeneration facilities that

harness waste heat from their industrial processes.

A price freeze that keeps consumers’ costs low retards such reductions in the

demand for electricity. By protecting consumers from price volatility, a freeze can

also dampen their incentive to invest in the ability to alter electricity purchases on

short notice—such as by owning auxiliary petroleum- or gas-fired generators—or

even to sign up for interruptible service with their utility. The absence of a consumer

response to price changes places a greater burden on suppliers to adjust to shifting

market conditions.

The Restrictions on Long-Term Contracts

California's Public Utility Commission generally interpreted the restructuring plan as

incompatible with allowing the utilities to contract for long-term power supplies

outside the PX (until its termination) and the CAISO. That restriction applied to two

types of long-term arrangements: contracts that the utilities made in the futures

market and contracts in which the independent producers that had purchased the

utilities’ generating assets agreed to supply the utilities with a certain amount of

electricity in the future.32

The PUC’s opposition to long-term contracts was consistent with the plan's

emphasis on creating a competitive wholesale market and giving that market a big role

in determining the wholesale price of electricity. Indeed, in California, the spot

market ended up supplying about half of the utilities’ demand for power, on average,

compared with only about 10 percent to 20 percent in other restructured service
22 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

33. California State Auditor, Energy Deregulation, p. 24. 

areas, such as Pennsylvania, New Jersey, Maryland, and the New England states.33

California’s reliance on spot-market purchases was even greater during periods of

peak demand. But the utilities could not defend themselves against increases in

wholesale prices by using their traditional recourse to self-supply or other riskmanagement strategies. The rationale for discouraging long-term contracting, like

that for the retail price freeze, rested in large part on the assumption that available

generating capacity would remain large enough to keep wholesale prices low.

Historically, California’s big private utilities had not faced significant risk of

adverse price movements caused by changes in supply or demand. In collaboration

with the PUC, the utilities maintained a high margin of reserve capacity, which was

included in their rate base and thus paid for by customers. (A high reserve margin

contributes to reliability of service for consumers by making disruptions of service less

likely in the event that generating units are unexpectedly idled or load increases.)

Under the restructuring plan, by contrast, the new reliance on spot-market purchases

and the retail price freeze made the utilities subject for the first time to the risk of

financial loss if wholesale prices rose. Their ability to limit that type of risk was

sharply curtailed by the plan's restrictions on the use of long-term supply contracts

and futures markets and by the requirement that they sell much of their powergenerating capacity.

It is not clear that the utilities recognized their new exposure to market risks or

that they would have acted to reduce that exposure if they had been allowed to do so.

Some accounts suggest that initially, the utilities did not want to sign long-term, fixedprice contracts because long-term prices were generally higher than the spot prices

they were paying in the PX and CAISO auctions and they were trying to maximize

cash flow to recover their stranded costs.

Had the utilities been able to enter into long-term contracts that guaranteed their

future cost or supply of electricity, such arrangements would have helped diminish the

shortage of power-generating capacity—and thus reduced the upward pressures on

prices. Such long-term guarantees would have encouraged independent generators

to build new capacity and would have improved the utilities’ financial position, so

generators might not have charged higher prices as compensation for the risk of

nonpayment by the utilities.

Because the investor-owned utilities were not able to protect themselves from

the risk of adverse movements in wholesale prices and because retail prices were

frozen, consumers were exposed to the risk of losing service. Furthermore, the plan’s

heavy reliance on the spot market to meet peak-period demand potentially gave independent generators a great deal of power over that market.
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 23

34. For a discussion of competition in the California market, see Severin Borenstein, James Bushnell, and

Frank Wolak, Diagnosing Market Power in California’s Restructured Wholesale Electricity Market,

Working Paper No. 7868 (Cambridge, Mass.: National Bureau of Economic Research, September

2000).

35. For a discussion of how the auctions and price caps operate, see California State Auditor, Energy

Deregulation.

Flawed Auction Markets, Price Caps, and Market Power

The spot market for electricity created by California's restructuring plan comprised

the PX and CAISO auctions, the rules governing those auctions, and oversight by the

FERC. Prices in spot markets for electricity can change quickly and dramatically

because both the short-term demand for electricity and (without a large reserve

margin) the short-term supply are not very responsive to changes in price. In other

words, in a tight market, only a very large price increase can produce the combined

responses in demand and supply that are necessary to avoid a supply shortage.

As with many features of California’s plan, the spot market might have worked

better if a sufficient reserve of peaking capacity had existed, as was assumed when the

plan took effect. Not only did the potential for large price increases grow as the reserve margin disappeared, but some analysts believe that features of the market’s

design contributed to even larger price increases. Those analysts point to the design

of the PX and CAISO auctions, the price caps established for the CAISO market, and

the withholding of supplies during certain periods.34

The design of the auction systems may have given individual sellers an opportunity to engage in strategic bidding to secure higher prices.35 Sellers in the PX

auctions submitted bids in the form of a supply schedule; the markets’ operators then

scheduled power generation by those individual sellers, from the lowest-cost to the

highest, until all of the demand to be met by the auction had been satisfied. In the

CAISO auctions, sellers submit single-price bids, subject to a price cap that may be

lifted during emergencies. In both markets, the price paid to all successful bidders

reflects the cost of the last and most expensive increment of supply from the highest

bidder. Some analysts believe that the PX system gave sellers an incentive to submit

supply schedules with relatively low prices (reflecting actual costs) for most of their

sales and very high prices (exceeding costs) for the last units of power offered. The

idea was that sellers expected sometimes to be awarded that top price for all of their

sales but never risked not selling the bulk of their power.

The CAISO established price caps to eliminate the temporary spikes in prices

that can occur during periods of peak demand. Those caps may have served as a focal

point when sellers set the top price in their supply bids. That is, the existence of caps
24 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

36. From the buyers’ perspective, the price cap in the CAISO auction would have represented the maximum

price they would want to pay in the PX auction. If the PX price ever exceeded the CAISO price, buyers

would reduce their demand bids in the PX auction and allow the CAISO to make purchases on their

behalf. 

in the CAISO market may have encouraged bidding in the CAISO and PX markets

at higher prices.36

The caps probably did not achieve their goal of effectively restraining prices.

The CAISO had discretion to lift its caps altogether if it believed that a supply

shortage was imminent. If sellers withheld supply in the day-ahead market—so that

it looked to the CAISO as though a real-time shortfall was imminent—the CAISO

was more likely to lift its caps. Indeed, independent power producers reportedly

avoided the caps by selling some power to municipal utilities in California and to

utilities outside the state for resale to the CAISO, since out-of-market sales by those

utilities to the CAISO were never subject to caps.

It is also possible that individual sellers tacitly colluded to withhold supplies in

order to push prices above competitive levels. Taking advantage of the designs of the

auction system and price caps (to bid prices that exceeded costs) would enable those

suppliers to realize above-market prices and profits from withholding supplies.

However, evidence about how much, if any, capacity was withheld for competitive

rather than legitimate operational reasons is unclear. Academic and legal debate

continues over the extent to which the price increases of the past year resulted from

exercises of market power by electricity generators. Discussions about whether

specific laws have been broken focus on the Federal Power Act and its requirement

that wholesale electricity rates be “just and reasonable,” as well as on general antitrust

statutes that prohibit price fixing.

Regulated Power Markets in California and the Rest of the West

Another way in which California’s restructuring plan helped turn the market stresses

of mid-2000 into a crisis was by not adequately taking into account how dependent

the state’s large investor-owned utilities were on other utilities, both inside and outside California. The legislation that authorized the plan did not require all utilities in

the state to participate in the new market, and California law of course did not govern

other states’ utilities or federal power agencies. The three private utilities covered by

the plan buy only a small part of their electricity from those sources; but at the critical

margin, constraints on the flow of power into the new wholesale market probably

influenced the source and cost of the last kilowatt hour of power, which determined

the price for all of the electricity sold in the market.
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 25

37. The Bonneville Power Administration (BPA) may sell excess power at higher rates outside the region

and does sell some power to California’s municipal utilities. The Western Area Power Administration

(WAPA) sells to municipal utilities and cooperatives throughout the West at prices established under

terms similar to those for the BPA. The subsidies implicit in federal rate-setting and the reliance on

hydropower cause federal rates to be much lower than prices from nonfederal producers. Although the

BPA and WAPA are not free to sell to investor-owned utilities in California, both agencies engage in

power swaps with those utilities, dispatching federal power today to be repaid with California utility

power at a later date.

Specifically, the restructuring plan did not include 38 municipal and cooperative

utilities (most notably the Los Angeles and Sacramento municipal utility districts).

It also did not cover three small investor-owned utilities in the state. Together, those

excluded utilities account for about 30 percent of direct retail sales of electricity in

California. The state’s municipal utilities did not want to join the restructured electricity market for at least two reasons. First, they did not have the same high exposure to stranded costs that the private utilities did, and hence, they did not need the

state’s plan to recover those costs. Second, they receive a federal tax preference that

could have been jeopardized if they had sold too much power, under the plan, to other

utilities (see Box 2).

Other constraints on the flow of power to the wholesale market include various

types of regulations, such as the regional-preference and average-cost-pricing rules

of the utilities outside the restructuring plan and regulations that impede the regional

transmission of electricity.

Regional-Preference Rules. Power from utilities outside California has not been completely free to flow in response to price signals in the state’s wholesale market. Those

utilities (like municipally owned and cooperative producers within the state) are required to meet the power demands of their service areas before exporting power to

other markets, even if wholesale prices are higher elsewhere. Similar regional-preference rules make it difficult for more power to flow to California from the federally

owned Bonneville Power Administration and Western Area Power Administration.

Those agencies supply about 10 percent of the California market, on average—mainly

through sales to municipal and cooperative utilities. But most of their relatively inexpensive hydropower goes to municipal utilities, cooperatives, and industrial customers

in the northwestern states.37

The regional-preference rules of local utilities and federal power agencies have

the effect of impeding energy flows across the western states largely because the

customers of that power do not have full rights to its use. In particular, they do not

have the right to resell the power on their own or to receive compensation if the utility

sells it elsewhere. That restriction has weakened somewhat in the past year, with
26 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

BOX 2.

MUNICIPAL UTILITIES AND THE FEDERAL TAX EXEMPTION

FOR STATE AND LOCAL BONDS

Many local governments operate electric utilities, generally known as municipal utilities (or

munis). The munis engage primarily in retail distribution, buying power from others and selling

it to homes and businesses in their service areas. But some munis, including the Sacramento

Municipal Utility District (SMUD) and the Los Angeles Water and Power District (LAWPD), also

generate their own power.

The munis, like other state and local government entities, commonly issue bonds to pay for

construction. The interest on such bonds is generally exempt from federal taxation. As a consequence, bondholders are willing to accept a reduced interest rate, and the munis can borrow at

favorable rates. Federal policy favors the munis in other ways, too: by exempting their income

from federal taxation and by giving them preferential access to low-cost federal power.

Federal restrictions on the use of the munis’ borrowed funds have made California’s munis

reluctant to sell power to the state’s investor-owned utilities for fear of losing the tax exemption

on their bonds. The federal government limits the use of tax-exempt bonds in financing public

facilities in order to prevent state and local officials from using the proceeds to make favorable

loans to private businesses. Section 141 of the Internal Revenue Code generally allows no more

than 10 percent of bond proceeds to be used by a private business if that business is receiving

favorable electricity rates or is outside a muni's traditional service area. That private-use restriction applies over the life of a bond issue, and violation can result in the interest income becoming

taxable retroactively.

Participation by munis in a restructured electricity market could violate the private-use rule

and trigger taxation of interest payments on their bonds.1

 One example relates to munis' power

sales. Selling power to utilities outside a muni's service area, if that power was generated by or

transmitted over facilities financed with tax-exempt bonds that have not been paid off, could

violate section 141. A second example relates to power distribution for others. Allowing

investor-owned utilities to use a muni's distribution facilities that were financed with tax-exempt

bonds that are still outstanding could also violate section 141. In 1999, the SMUD and LAWPD

made about 15 percent of their power sales to other utilities. However, that electricity was

generated at debt-free facilities (no longer subject to the private-use rule), was sold in short-term

spot markets consistent with Internal Revenue Service regulations, or fit under the allowable

limits on private use.

_________________________

1. See Dennis Zimmerman, Electricity Restructuring and Tax-Exempt Bonds: Economic Analysis of Legislative

Proposals, Report RL30411 (Congressional Research Service, January 20, 2000).
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 27

38. A notable example is Kaiser Aluminum, which buys electricity from the Bonneville Power Administration. Kaiser chose to shut down its aluminum operations until the fall of 2001 (when its current contract

with BPA expires) in order to resell its cheap BPA power to California. The BPA is acting as Kaiser’s

marketing agent, selling most of the power at full market prices minus a small marketing fee. Kaiser

employees continue to be paid during the shutdown.

some suppliers offering to pay large customers not to take power (as part of their

programs for demand-side management) and others granting sale rights.38

Average-Cost Pricing. A common feature of power regulation in the United States

is that a regulated provider of electricity sets a price that reflects its average costs.

All of the utilities outside California’s restructured market generally adhere to that

pricing rule. However, average-cost pricing reduces incentives for the customers of

those utilities to limit their consumption when power costs rise. Such conservation

would help free up supplies that could be sold on the wholesale market.

Although some of those utilities have been forced to buy increasingly expensive

power in the wholesale market to compensate for high demand and lost hydropower

capacity, price increases to their local customers have been held down by the

continuing low costs of the power they generate themselves or buy from the federal

government. As with regional preferences, the problem here lies not just with

average-cost pricing but with the rights to the power: customers would have full

incentives to conserve in the face of rising spot prices if they could resell that power

in the wholesale market.

Transmission Bottlenecks. Other types of regulation, related to the construction of

transmission lines and the pricing of transmission services, also impede the flow of

electricity from regions where it can be produced at the lowest cost to regions where

consumers value it the most. Individual transmission systems are generally part of

broad power grids that connect many states. For that reason, transmission services

and rates are regulated by the federal government. (Only in Texas, where transmission is entirely within the state, is there no federal role.) Decisions about the construction and siting of transmission lines, however, are primarily a local affair. With

the growth of nonutility suppliers and wholesale competition, power is moving across

transmission lines in directions and volumes that the utilities that designed the systems

did not envision. Those new flows have created bottlenecks in the delivery of power.

The building of new transmission capacity to remove bottlenecks is limited by

two factors: the extent of local control over construction decisions and the way in

which transmission services are priced. Requests for permission to build transmission

lines must come from local utilities, which are state-franchised monopolies, and must

be approved by local regulators. Investments that create opportunities for outside

utilities or independent power producers to compete in a local market or that appear
28 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

primarily to benefit other communities may be suspect. The siting of transmission

lines is also dependent on local approval and environmental considerations.

The regulation of prices for transmission services may also mute economic

signals about when and where to add new capacity. Most transmission lines in the

United States are owned by private utilities or the federal government. The principal

regulatory agency for private lines is the FERC, which sets prices for transmission on

the basis of a utility’s average systemwide cost of building and operating transmission

lines, a fair market return on the utility’s investment, and its current operating costs.

The federal power agencies (such as the Bonneville Power Administration) are largely

self-regulating. They set their own systemwide transmission rates on the basis of historical capital costs and current operating costs. The average-cost-pricing rules used

by the FERC and the federal agencies do not provide incentives to add capacity to

congested parts of the transmission grid.

CALIFORNIA’S RESPONSE: A NEW ROLE FOR STATE GOVERNMENT

A broad goal of restructuring in California was to secure the benefits of competition

for electricity consumers in two ways: by breaking up the vertically integrated, stateregulated monopolies to create more wholesale suppliers, and by giving retail customers the chance to choose their power producer. However, the state’s response to

the crisis and its efforts to secure adequate electricity supplies and control volatile

wholesale prices are leaving California with a new market structure.

The new market differs from the old regulated-monopoly system, from the

interim restructuring plan, and from the competitive ideal that the state was working

toward. Beginning in January 2001, the governor, the California legislature, and the

Public Utility Commission acted to give the state a long-term role in buying wholesale

power on behalf of private utilities. Lawmakers are also moving toward establishing

a new state-owned utility that would not only buy power but also own and operate

the transmission systems of the state’s private utilities and build and operate new

generating plants. The state has effectively abandoned the freeze on retail electricity

prices, raising rates to help cover its costs of buying power.

The New Purchasing Agency

The California agency now charged with purchasing electricity is the Department of

Water Resources (DWR). That department has become one of the largest buyers of

electricity in the country. It has reportedly signed contracts that cover 90 percent of

the wholesale purchasing requirements of the state’s three large investor-owned

utilities—or about one-third of California’s total power use. In addition, a new

agency, the California Consumer Power and Conservation Authority, will acquire
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 29

generating capacity to supplement the state's supplies and sell the power it generates

to the DWR. A new state bureaucracy will also be needed to manage much of California's transmission grid if the state is successful in taking over the transmission lines

of the three large utilities.

California is planning the largest state or local bond issue in history—as high as

$13.4 billion—in the fall of 2001 to finance its purchases of electricity and natural gas

in 2001 and its acquisition of private transmission assets. Revenue from the sale of

those bonds may also be used to help shore up the financial position of the private

utilities. In the first seven months of 2001, the DWR spent about $9.5 billion from

its general fund and from short-term borrowing to buy electricity and natural gas

(recouping only about $1.5 billion from reselling that power to utilities). The agency

made those purchases in the spot market for immediate delivery as well as in the

markets for short- and long-term delivery, with signed contracts valued at over $45

billion. The contracts guarantee delivery for various periods, some as long as 20

years.

With the emergence of the DWR, the role of the state’s private utilities and the

PUC (which regulates those utilities) is diminishing. And with one large buyer replacing three utilities in the state’s wholesale market, competition will most likely diminish

as well. Those utilities may keep their nuclear and hydropower generating plants and

their long-term supply contracts with qualifying facilities, but otherwise they will have

a small presence in the wholesale market. Instead, the utilities will act as distributors

of power purchased by the state, charging retail customers for the full cost of those

purchases.

The future position of the state’s independent power producers may also be in

question. Not only are they facing fewer buyers, but their biggest customer, the state,

may have the authority to seize their assets if it believes they are charging too much

for electricity or restricting supplies. The California Senate passed a resolution in July

2001 indicating that it would support the governor in such a seizure. 

In August, the PUC effectively yielded authority to the DWR to set retail electricity rates without public review in order to ensure sufficient revenues to cover its

bond issue. (Both organizations are subject to direction from the governor’s office,

which appoints members to the PUC and selects managers of the DWR.) The PUC

had already approved rate hikes in January and March to help cover the state’s costs.

In future, the state will direct the large private utilities to set rates that will repay

expenses incurred in 2001 and cover the state’s current costs of buying power. The

state plans to secure its upcoming bond issue with those power revenues. The PUC

will continue to oversee the part of the retail rate that covers the utilities’ cost of

generating electricity, having power purchased on their behalf, and distributing power.

It is not clear which organization—the PUC, DWR, or a new agency—would decide
30 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

39. California Department of Water Resources, “July Energy Costs Down Significantly” (press release,

Sacramento, July 16, 2001), available at www.owe.water.ca.gov/newsreleases/2001/7-16-01energycosts.

html.

what rates are necessary to finance operations of a future state-owned transmission

grid.

Implications of the State’s New Role

California’s actions represent a blunt solution to the problems of insecure supply and

volatile prices—a solution that ultimately may present the state with many of the same

problems that restructuring was intended to solve. The goal of securing the benefits

of competition appears to be farther away than ever. For example, tension exists

between the state’s need to raise rates to pay for the debt it incurred during the crisis

and the right of ratepayers in a competitive market to contract with other power providers. In fact, since the rate hike of March 2001, some industrial customers have

begun exercising their option to choose other suppliers. As a result, the state wants

to rescind that option for all customers. The situation is similar to the one that prevailed before the crisis, when utilities with stranded costs opposed a rapid switch to

a competitive system because it would leave them unable to recover those costs from

ratepayers.

Two other factors that could make it harder to achieve the goal of competitive

prices are the lack of transparency of state actions and the possibility of government

subsidies to the state electricity business. In general, the state will not be subject to

oversight in its rate setting. Electricity rates are supposed to cover financing costs,

current power costs, and administrative costs. Because the state is actively concerned

about security of supply, it may be putting too much emphasis on costly long-term

contracts—much as the private utilities relied too heavily on risky spot-market

purchases. Already, in July 2001, as demand and wholesale prices dropped with

moderate weather in the West, the average cost of the state’s power purchases ($133

per mWh) rose above the average price in the spot market ($82 per mWh).39 Those

and any future losses on power purchases will be passed on to consumers. Moreover,

it is not clear what “administrative costs” of the state will find their way into retail

electricity prices. With no oversight, California has already demonstrated its reluctance to publish information about the contracts it has signed or its costs of purchasing power and has released that information only under court order.

If the state cannot recover all of its electricity-related costs through retail prices,

California taxpayers will have to make up the difference. In short, the state may be

at risk of creating a major government-subsidized industry—an industry that private

suppliers could be at a disadvantage in competing against.
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 31

40. Any increase in the distance that power is transmitted will result in some additional transmission losses

(about 9 percent of the electricity that leaves power plants is lost to heat transfer, which results from

resistance in the power lines).

LESSONS FOR FUTURE RESTRUCTURING EFFORTS

California’s problems have occurred at a time when many other states are restructuring, or are debating the merits of restructuring, their electricity markets. The experience of California suggests several lessons for those states about both the supply and

demand sides of electricity markets. In particular, if markets rather than regulation

are to determine the price of power, prices must be allowed to respond when unanticipated disturbances occur—such as last year's very hot summer in the West. The supply and demand sides of the market together must be sufficiently robust to dampen

such swings.

Supply-Side Lessons

The lessons for the supply side of the market are twofold. First, restructuring is more

likely to succeed when more of the power in a market is free to respond to price

signals. As California attempted to restructure, regulatory constraints limited the flow

of power to the state's wholesale market from municipal utilities in California, from

utilities in other states, and from federal power agencies. Second, utilities should be

free to manage the risks of adverse price movements in that competitive environment

by entering into long-term contracts. One lesson not to take from the California experience relates to the size of the reserve margin: building enough generating capacity

to meet the demand for electricity under any scenario may not be cost-effective.

If restructuring is to allow supply to be more responsive to prices by moving

power within the market, it must also address regulatory barriers to the construction

and operation of transmission systems. A restructured market that works well will

probably feature an immediate increase in the demand for transmission services, as

communities increasingly acquire power from new sources in new locations not

envisioned by the original designers of the transmission grid.40 The regionwide costs

of supplying electricity can drop if low-cost generators from some states in the region

are able to provide more power than before. Moreover, the responsiveness of regionwide supply can improve if additional suppliers from part of the region are able to put

more power into the grid to offset disruptions in supply locally or unexpected surges

in demand elsewhere in the region. To realize those gains, however, consumers must

be willing to accept a trade-off: the lower prices that result from access to out-ofstate power supplies will sometimes rise when their state sends supplies to other parts

of the region.
32 CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS September 2001

41. See Federal Energy Regulatory Commission, "Regional Transmission Organization," Order No. 2000,

Federal Register, vol. 65 (January 6, 2000), p. 809.

Making sure that transmission capacity does not limit the responsiveness of

supply may require changing how transmission services are regulated and priced (to

create appropriate incentives for new construction) and how new lines are approved.

For example, some analysts have called for charging different, market-sensitive rates

for transmission in different parts of the overall system—a practice known as node

pricing—to provide greater incentives for construction to remove bottlenecks. The

FERC believes that creating regional transmission organizations to operate large

sections of the grid could help, too.41

Restructuring is also more likely to be successful if utilities are allowed to use

standard risk-management tools. Letting utilities both enter into long-term contracts

with suppliers at fixed prices and hedge through the futures market would help

protect them from the financial difficulties that have plagued California’s power

distributors. It would also enable the utilities to offer greater price certainty to their

customers (in place of a freeze on retail rates). That price certainty is important not

just because it protects against high prices but because it creates a better climate for

producers, distributors, and consumers.

Having a large reserve of generating capacity could ease the transition from a

regulated to a competitive market structure. Indeed, if California had implemented

its plan in the early 1990s, when the state’s utilities still possessed more capacity than

they needed, the market could have better handled the stresses that arose in the summer of 2000. That improved response could in turn have masked some of the faults

of the restructuring plan.

Creating such a reserve as a matter of policy, however, is an expensive way to

ensure price stability. One of the reasons that the state moved to a competitive

market structure was to help reduce electricity prices by lowering the costs of the

utilities’ reserve capacity. In a competitive market, producers’ investment in reserve

capacity should be consistent with the amount of price stability (or, equivalently,

supply security) that consumers are willing to pay for in the form of long-term supply

contracts.

Demand-Side Lessons

California's freeze on retail rates inhibited the response of electricity users to the

state’s supply problems. Thus, it proved to be a major factor in the ensuing crisis.

A simple lesson of that experience is that consumers need to face the real cost of

electricity. Exposing consumers to price changes will induce them to increase their

use of power when prices fall and curtail it when prices rise. When prices do not
CAUSES AND LESSONS OF THE CALIFORNIA ELECTRICITY CRISIS 33

42. See Stephen J. Rassenti, Vernon L. Smith, and Bart J. Wilson, Demand-Side Bidding Will Control

Market Power, and Decrease the Level and Volatility of Prices (Tucson: Economic Science Laboratory,

University of Arizona, February 2001); Severin Borenstein, The Trouble with Electricity Markets (and

Some Solutions), Working Paper PWP-081 (Berkeley, Calif.: University of California Energy Institute,

Program on Workable Energy Regulation, January 2001), available at www.ucei.berkeley.edu/ucei/PDF/

pwp081.pdf; and Paul Joskow, “Deregulation and Regulatory Reform in the U.S. Electric Power Sector”

(paper prepared for the Brookings-AEI Conference on Deregulation in Network Industries, December

10, 1999, revised February 17, 2000), available at http://econ-www.mit.edu/faculty/pjoskow/files/

BrookingsV2.pdf.

change along with costs, and when the amount of power demanded cannot respond

to prices in that way, a greater adjustment must be made on the supply side of the

market.

Price signals should encourage consumers not only to buy more or less power

now but also to invest in the ability to adjust their future power use. Some of the

same demand responsiveness that results from having consumers pay market prices

may also be achieved if utilities either compensate customers for reducing their use

or allow customers to resell power to others (in which case, a third party is paying

them to reduce their use). 

An important distinction exists between long- and short-term capabilities for

lowering power use. In California, consumers have already responded over the years

to high electricity prices by, among other things, adding thermal insulation to buildings, purchasing efficient appliances, and switching to natural gas. Those are longterm investments. Indeed, the state ranks among the lowest nationally in per capita

use of electricity by households. However, electricity consumers—particularly households—have acquired few devices that would let them reduce electricity use on short

notice, such as real-time meters (which would tell them when prices were changing),

backup power supplies, or dual-fuel capabilities. One reason is that consumers do not

usually face real-time prices (in particular, the full cost of generating electricity during

peak-use times). Another reason is that although electricity prices in California have

been high overall, they have historically been stable.

Some analysts believe that the supply adjustments and resulting price increases

in California would have been much smaller if various techniques to manage demand

had been in wide use before restructuring.42 For example, several approaches can

make real-time pricing easier, such as technologies that monitor electricity use and

prices, and contracting arrangements with electricity suppliers that permit the customer (or a designated agent) to interrupt service when the price rises. In many cases,

large industrial customers already have the capacity to monitor and adjust their

demand in the face of rising prices and, in fact, do so. Successful restructuring may

necessitate that residential and commercial customers acquire many of the same

demand-management capabilities that industrial consumers have.




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