High Risk:

The California State Auditor Has Designated Electricity Production 

and Delivery as a High-Risk Issue

June 2009 Report 2008-602

C A L I F O R N I A 

STATE AUDITOR
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CALIFORNIA STATE AUDITOR

Bureau of State Audits Doug Cordiner

Chief Deputy

Elaine M. Howle

State Auditor

555 Capitol Mall, Suite 300 Sacramento, CA 95814 916.445.0255 916.327.0019 fax www.bsa.ca.gov

June 16, 2009 2008-602

The Governor of California

President pro Tempore of the Senate

Speaker of the Assembly

State Capitol

Sacramento, California 95814

Dear Governor and Legislative Leaders:

As authorized by Chapter 251, Statutes of 2004, the Bureau of State Audits (bureau) presents its 

report designating the production and delivery of electricity as a high-risk issue in California. In 

May 2007 the bureau published its initial assessment of issues that pose a high risk to California, 

its citizens, and select state agencies. Our initial assessment identified five significant statewide 

risk areas and two specific state agencies facing challenges to their day-to-day and long-term 

operations. Because of the ongoing challenges the State faces to ensure a reliable supply of 

electricity, which is critical to our economy and daily lives, the bureau has added the production 

and delivery of electricity to its list of high-risk issues.

Since California’s restructuring of the electricity industry in the late 1990s and the subsequent 

energy crisis of 2000 and 2001, the electricity sector has continued to evolve. In fact, industry 

observers suggest that the actions the State and other market participants have taken have 

decreased the risk of another energy crisis. However, these stakeholders continue to work 

to resolve issues and to further refine the actions taken to alleviate the earlier energy crisis. 

This report also identifies significant new issues and challenges in the electricity sector that 

the State faces, which have the potential to influence the supply of electricity, its transmission, 

and consumer rates. For example, we found that decisions concerning certain environmental 

policies may substantially reduce electricity supplies from existing power plants and restrict 

the construction of new power plants, most notably in Southern California. We also found that 

the State’s ability to meet the targets it has adopted to increase the use of renewable sources 

of electricity is constrained by various obstacles that are preventing the construction of key 

infrastructure. We further found that a proposed reorganization of certain energy-related 

programs and functions present additional uncertainties related to the State’s ability to formulate 

strategic energy policies. Because we have designated the production and delivery of electricity 

as high risk, the bureau will continue to monitor developments and challenges that affect the 

reliability and affordability of electricity, and may undertake future projects to further evaluate 

policy changes that potentially affect electricity supplies and rates in California.

Respectfully submitted,

ELAINE M. HOWLE, CPA 

State Auditor
California State Auditor Report 2008-602 vii

June 2009

Contents

Summary 1

Introduction 5

Analysis Results 

Various Factors Contributed to the Energy Crisis of 2000 and 2001 17

Mitigating Actions Have Reduced the Likelihood of Another 

Energy Crisis 20

The Need to Replace or Retrofit Aging and Environmentally Harmful 

Power Plants May Cause Significant Reductions in Electricity Supplies 26

Large Investor‐Owned Utilities Have Secured Long‐Term Contracts 

as Water Resources’ Role Phases Out, but Some Uncertainty Remains 32

Meeting California’s Renewable Resource Targets Will Be Challenging 37

It Is Too Early to Tell Whether the ISO’s New Market Structure Will 

Continue to Succeed 39

Several Entities Have Identified a Need to Reorganize the State’s 

Energy‐Related Entities 43

The Bureau Will Continue to Monitor Developments in the Electricity 

Sector and in Related Policies and Programs 44
California State Auditor Report 2008-602 1

June 2009

Summary

Results in Brief

Because California’s electricity sector faces multiple challenges 

and problems related to energy production and consumption, the 

Bureau of State Audits (bureau) has added the production and 

delivery of electricity to its list of issues that pose a high risk to 

the State of California (State) and its citizens. The reliable supply 

of electricity provides a critical foundation both for California’s 

economy and its citizens’ standard of living. The electricity industry 

is evolving to address problems highlighted by the energy crisis 

of 2000 and 2001 while simultaneously working to introduce 

mechanisms to increase competition and to support the State’s 

overall energy targets. Since the energy crisis, the State has 

continued to deal with the challenges of ensuring that sufficient 

capacity exists to generate the volume of electricity needed, 

that California has the infrastructure necessary to transport the 

electricity to the areas that most need it, and that the appropriate 

regulatory agencies work collaboratively in their efforts to ensure 

that an energy crisis does not reoccur.

In 1996, when the State took the lead in the national move 

toward restructuring the electricity industry to allow for greater 

competition, proponents assumed that these actions would reduce 

California’s electric rates. Despite this intent, the State experienced 

rolling blackouts and, in January 2001, the governor proclaimed 

a state of emergency. Wholesale electricity prices escalated to 

unprecedented levels. Because of a cap on retail prices, two of the 

State’s three largest electricity providers—Pacific Gas and Electric 

Company (PG&E) and Southern California Edison—could not 

recoup their costs from customers and PG&E ultimately filed 

for bankruptcy.

By many accounts, several interconnected events during the early 

part of the current decade contributed to the energy crisis. For 

instance, the State and energy providers did not meet increased 

demand for electricity with investments in new generation 

of electricity or in upgrades to the State’s system for transmitting 

electricity. Compounding this imbalance, a flawed market design 

relied too heavily on short-term markets, leaving participants 

overexposed to market manipulation that led to high wholesale 

prices. Because of the uncertainty related to the ability of the large 

electricity providers to secure enough energy supplies to meet 

their customers’ needs, the State took steps to alleviate the crisis, 

including procuring long-term power contracts to ensure both a 

reliable supply of electricity and rate stability.

Review Highlights . . .

Our review of California’s production and 

delivery of electricity revealed that since the 

energy crisis of 2000 and 2001, new issues 

and challenges could impact the supply of 

electricity, its transmission, and consumer 

rates. Some of these challenges include 

thefollowing:

» Numerous aging and environmentally 

harmful power plants need to be replaced 

or retrofitted.

» Key air and water policies could reduce 

the electricity supply from existing power 

plants and limit new plants.

» As the State’s remaining power contracts 

expire, there is uncertainty surrounding 

the ability of electricity providers to 

procure sufficient energy supplies.

» Uncertainties about the introduction of a 

new wholesale market structure.
California State Auditor Report 2008-602

June 2009

2

Since the energy crisis of 2000 and 2001, the electricity sector 

has continued to evolve. In fact, industry observers suggest that 

the actions the State has taken have decreased the risk of another 

energy crisis. However, the State and other market participants 

continue to work to resolve issues and to further refine the actions 

taken to alleviate the earlier energy crisis. In addition, significant 

new issues and challenges in the electricity sector have the potential 

to influence the supply of electricity, its transmission, and consumer 

rates. These issues include the following:

•	 The State’s need to replace or retrofit aging and environmentally 

harmful power plants.

•	 Ongoing decisions surrounding key air and water policies—most 

notably affecting Orange County and the urban portions of 

Los Angeles, Riverside, and San Bernardino counties—which 

may reduce the electricity supply from existing power plants and 

limit the siting, construction, and operation of new plants.

•	 Uncertainty surrounding the financial recovery of California’s 

large electricity providers and their ability to procure sufficient 

energy supplies to meet consumers’ needs as the State’s power 

contracts expire.

•	 The State’s targets to increase the use of electricity produced 

from renewable energy sources.

•	 Modifications to the market structure, such as the reinstatement 

of energy markets that failed at the height of the energy crisis; a 

new wholesale electricity pricing scheme; and the use of a new 

computer model of the electric grid that will allow, for example, 

better identification of transmission bottlenecks.

•	 A proposal currently before the Legislature to reorganize certain 

energy-related entities and create a new state Department 

of Energy.

Consequently, we believe that our list of high-risk issues should 

include energy concerns—and, more specifically, the areas related 

to supplying electricity to California’s citizens. We will continue to 

monitor new developments and challenges that affect the industry 

as well as their effects on the reliability and affordability of 

electricity. To the extent that resources are available, the bureau 

may undertake future projects that could include recommendations 

to improve electricity-related policies and programs and how 

best to implement those improvements. For example, the 

bureau may monitor developments in a court ruling regarding 

a proposed policy that potentially affects electricity supplies in 

Southern California. The bureau may report on the status of the 
California State Auditor Report 2008-602 3

June 2009

State’s expiring energy contracts and the ability of large electricity 

providers to procure sufficient energy supplies to meet consumers’ 

needs. Also, should major developments occur, the bureau may 

consider deeper evaluations of the new market structure, the State’s 

ability to meet its renewable resource targets, and, if one is created, 

the effectiveness of a new state Department of Energy.
California State Auditor Report 2008-602

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4

Blank page inserted for reproduction purposes only.
California State Auditor Report 2008-602 5

June 2009

Introduction

Background

In May 2007 the Bureau of State Audits (bureau) 

published its initial assessment of the high-risk 

issues that the State of California (State) and 

select state agencies face. As the text box shows, 

our assessment, titled High Risk: The California 

State Auditor’s Initial Assessment of the High‐Risk 

Issues the State and Select State Agencies Face, 

identified five significant statewide risk areas and 

two specific state agencies facing challenges to their 

day-to-day and long-term operations. High-risk 

programs and functions include not only those 

particularly vulnerable to fraud, waste, abuse, and 

mismanagement or that present major challenges 

associated with their economy, efficiency, or 

effectiveness, but also those of particular interest 

to California citizens and those that have or could 

have significant impacts on the public’s health, 

safety, and economic well-being.

In considering the criteria named above, we 

reviewed energy concerns—specifically those 

related to the electricity sector—to decide whether 

it belongs on the list of issues that are subject to the 

high-risk audit program authorized by California 

Government Code, Section 8546.5. Because the 

State is continuing to address the factors that 

contributed to the rolling blackouts earlier this decade and because 

it is attempting to address more current issues related to electricity 

generation, such as the State’s need to replace older power plants 

and its targets to increase the use of renewable energy, we believe 

such an assessment is warranted. For a description of the criteria 

used to determine whether an issue merits a high-risk designation, 

see the Appendix to our May 2007 report on high-risk issues. In 

addition, the text box on the following page lists the bureau’s most 

recent reports on the topic of energy.

The Electric System, Past and Present

The electric system is a network of infrastructure that allows 

consumers to have readily available electricity regardless of their 

proximity to power-generating facilities. As Figure 1 on page 7 

illustrates, the generation, transmission, and distribution of 

electricity are interdependent industry segments that function 

sequentially. Generated at power plants and then transported to

Statewide Risk Areas That the Bureau of State 

Audits Identified in May 2007

•	 Emergency preparedness

•	 Maintaining and improving infrastructure

•	 Information technology

•	 Management of human resources

•	 Other post-employment benefits of retiring

state employees

State Agencies That Meet the Criteria 

for High Risk

•	 Department of Corrections and Rehabilitation

•	 Department of Health Services*

Source: High Risk: The California State Auditor’s Initial Assessment 

of the High-Risk Issues the State and Select State Agencies Face, 

Bureau of State Audits, May 2007, 2006-601.

* Effective July 1, 2007, the Department of Health Services 

was reorganized and became two departments—the 

Department of Health Care Services and the Department 

of Public Health.
California State Auditor Report 2008-602

June 2009

6

consumers at their homes and businesses, 

electricity travels via high-voltage transmission 

lines and then through lower-voltage distribution 

lines that snake throughout communities and 

neighborhoods; taken together, the segments of 

this system are commonly referred to as the 

electric grid. Because energy providers cannot 

store significant amounts of electricity 

economically, the volume of electricity generated 

and supplied must almost exactly match the 

volume used by residents and businesses only 

milliseconds later. Should more or less electricity 

enter the grid than the amount used by customers, 

the grid could fail. Momentary imbalances can 

result in lights dimming or in brief power 

disruptions. However, more significant imbalances 

can cause cascading blackouts, such as the 

one that occurred in Ontario, Canada, and 

the Northeastern United States in August 2003. 

That cascading blackout left an estimated 

50 million people without power, some for up to 

four days, and cost the economy billions of dollars. 

To maintain electric grid balance, system 

operators, which include utilities and independent 

entities charged with the responsibility of 

monitoring and managing grid operations, can 

increase or decrease the volume of electricity put 

onto the grid, and they can reroute the flows of 

electricity through the various transmission lines and substations 

that make up the grid.

Before the passage of Assembly Bill 1890 (AB 1890) in 1996, 

which facilitated the restructuring of California’s electricity 

industry, three large investor‐owned utilities—or privately held 

utilities—owned and controlled the electric systems that served 

most Californians. The utilities owned and operated the capacity to 

generate, transmit, and distribute electricity. They also functioned 

as system operators, responsible for monitoring and maintaining 

the fine balance between electricity supplied and consumed. 

Electric utilities in general were interconnected to the extent 

that they could buy (import) and sell (export) electricity from 

one another as necessary, even over state lines, to ensure that their 

systems were in balance. Moreover, consumers were typically 

limited to purchasing power from the utility designated to serve the 

area in which the consumer was located; thus, consumer choice on a 

retail level did not exist. As natural monopolies, the investor-owned 

utilities were subject to state and federal government regulation: 

The California Public Utilities Commission (CPUC) oversaw 

retail rates in California, while the Federal Energy Regulatory

Reports Issued by the Bureau of State Audits 

on Energy Topics

Energy Deregulation: The Benefits of Competition Were 

Undermined by Structural Flaws in the Market, Unsuccessful 

Oversight, and Uncontrollable Competitive Forces, 

Report 2000-134.1, March 2001

Energy Deregulation: The State’s Energy Balance Remains 

Uncertain but Could Improve With Changes to Its Energy 

Programs and Generation and Transmission Siting, 

Report 2000-134.2, May 2001

California Energy Commission: Although External Factors Have 

Caused Delays in Its Approval of Sites, Its Application Process Is 

Reasonable, Report 2001-118, August 2001

California Energy Markets: Pressures Have Eased, but Cost Risks 

Remain, Report 2001-009, December 2001

California Energy Markets: The State’s Position Has Improved, 

Due to Efforts by the Department of Water Resources and 

Other Factors, but Cost Issues and Legal Challenges Continue, 

Report 2002-009, April 2003

Solar Energy: As the Cost of This Resource Becomes More 

Competitive With Other Renewable Resources, Applications 

to Construct New Solar Power Plants Should Increase, 

Report 2007-119, January 2008
California State Auditor Report 2008-602 7

June 2009

Figure 1

Electricity Supplies Must Be in Balance With Real-Time Consumption to 

Ensure the Integrity of Bulk Electric Systems and Reliable Service

Generation

Power plants

Wholesale

Substation

Electric grid

System operator*

Industrial 

customers

Commercial 

customers

Residential 

customers

Transmission

Distribution

Retail

Sources: Bureau of State Audits based on information from and discussion with the California 

Independent System Operator (ISO), and on information obtained from various Web sites, such 

as those maintained by the Federal Energy Regulatory Commission, the California Public Utilities 

Commission, and the Institute of Electrical and Electronics Engineers.

* A system operator is responsible for monitoring and ensuring equilibrium on the electric grid of 

electricity supplied and consumed in real time. The jurisdiction of a system operator is called its 

balancing authority area. The ISO manages roughly 80 percent of the State’s electric grid. Other 

system operators include municipal utilities and water irrigation districts.
California State Auditor Report 2008-602

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8

Commission (FERC) had regulatory oversight for the interstate 

transmission of electricity, including ensuring that wholesale 

rates were “just and reasonable.” The retail electricity prices set 

by the CPUC included the charges to cover the costs of generating 

the electricity as well as the costs of maintaining and operating the 

transmission and distribution systems. Utilities were allowed to 

earn a “normal rate of return” on all approved capital expenditures 

required to build generating facilities and on the transmission 

system itself.

As the next section discusses, after the passage of AB 1890 in 1996, 

market restructuring separated the wholesale segment of the 

industry (electricity generation) from the retail segment (electricity 

distribution). Nonetheless, the three large investor-owned utilities 

continue to deliver electricity to most consumers in California.

Figure 2 illustrates the areas served by the seven investor-owned 

utilities providing electricity retail service in California as well 

as those areas served by municipal utilities and rural irrigation 

districts. We use the term large investor‐owned utilities to 

refer solely to the three largest investor-owned utilities 

in California—Pacific Gas and Electric Company (PG&E), Southern 

California Edison, and San Diego Gas & Electric Company. Serving 

a substantial proportion of California consumers, these providers 

manage sizeable operations that involve complex electricity 

generation, transmission, and distribution systems. According 

to the California Energy Commission (Energy Commission), 

the State’s principal energy policy and planning agency, the 

operating decisions made by the large investor-owned utilities 

have potentially significant statewide impacts. In contrast, the 

small investor-owned utilities—Bear Valley Electric Service and 

Mountain Utilities—manage less complex electric systems that 

may not even be connected to the grid and serve much smaller 

populations. Finally, as the Energy Commission explained to 

us, the utility commissions of other states primarily regulate 

the multijurisdictional investor-owned utilities—Sierra Pacific 

and PacifiCorp—that operate in California. The CPUC provides 

oversight for the fraction of the two utilities’ total costs expected to 

be recovered from their California customers, who receive services 

from these multijurisdictional utilities for various reasons, such as a 

significant barrier existed between the locations of these electricity 

consumers and the nearest California utility or the locations were 

too far from a California utility. In addition to electricity services 

provided by the investor-owned utilities, publicly owned municipal 

utilities (municipal utilities) and irrigation districts manage 

approximately 20 percent of California consumers’ electricity 

demand. In place of the CPUC and its regulating authority, a board 

of directors sets rates and enforces pertinent rules and regulations 

for each municipal utility and irrigation district.
California State Auditor Report 2008-602 9

June 2009

Figure 2

Service Areas of California’s Electric Utilities and of Its Independent System Operator

PacifiCorp*

Pacific Gas and 

Electric Company†

Southern California Edison†

Bear Valley Electric Service‡

San Diego Gas and Electric Company†

Sierra Pacific Power Company*

Mountain Utilities‡

Balancing authority area of 

the California Independent 

System Operator (ISO)

Municipal utilities and 

irrigation districts not 

part of ISO’s balancing 

authority area

Source: California Energy Commission.

Note: Areas shown in white are served by various publicly owned utilities, including municipal utilities and irrigation districts.

* Multijurisdictional investor-owned utility.

† Large investor-owned utility.

‡ Small investor-owned utility. Bear Valley Electric Service is within ISO’s balancing authority area. Mountain Utilities is not connected to the 

high-voltage electric grid.

The Restructuring of California’s Electricity Industry

Since the late 1970s, under the direction of various federal laws and 

regulations, the nation has moved to open the electricity industry 

to competition. For example, the federal government required 

investor-owned utilities nationwide to purchase electricity supplies 

from alternative sources not generated by the utilities themselves, 

such as from wind and solar energy, and to partially open their 
California State Auditor Report 2008-602

June 2009

10

transmission systems to allow electricity to pass through to 

neighboring utilities’ service areas. Cumulatively, such actions were 

intended to create an energy market that encouraged competition.

In 1992, prompted by the federal Energy Policy Act and California’s 

high electricity rates, the CPUC began a comprehensive review 

of the electricity industry. This review led, in 1994, to a formal 

rulemaking proceeding to consider possible approaches to the 

restructuring of the industry. In December 1995 and January 1996, 

the CPUC issued decisions to guide restructuring in California. In 

response to concerns raised by FERC, these decisions encouraged 

investor-owned utilities to transfer voluntarily to unrelated parties 

the ownership of at least 50 percent of their generation facilities 

powered by fossil fuel. Additionally, the decisions required 

investor-owned utilities to transfer control, but not ownership, of 

their transmission facilities to an independent system operator. 

The CPUC also called for the creation of a power exchange, or 

a wholesale market through which the utilities must sell any 

electricity generated by facilities that they still owned and must 

purchase all electricity required to meet their consumers’ needs.

In 1996 the State then took the lead in the national move toward 

restructuring the electricity industry when the Legislature passed 

AB 1890, which codified many of the recommendations included in 

the earlier CPUC decisions. The legislation created two nonprofit, 

public-benefit corporations, the California Independent System 

Operator (ISO) and the Power Exchange (PX), as well as the 

Electricity Oversight Board1 to oversee the PX and the ISO. 

The Legislature also froze the retail rates that a utility could charge 

its consumers until March 31, 2002, or earlier if the utility had fully 

recovered certain costs.

Under the restructured electricity scheme, retail consumers could 

select their electricity suppliers; they were no longer obligated 

to purchase their power from the utility that serviced their area. 

Specifically, consumers could choose direct access, a retail option 

that enabled consumers to select an electricity provider other than 

the one that had previously supplied their electricity. On the other 

hand, these consumers were not obligated to switch. It was assumed 

that these actions would reduce California’s electric rates by at least 

20 percent by April 1, 2002. Municipal utilities, rural irrigation 

districts, and their customers were exempt from AB 1890.

1 The Electricity Oversight Board ceased operations on April 1, 2008. According to the Department 

of Finance, other entities such as the CPUC and the ISO have taken on some of the Electricity 

Oversight Board’s responsibilities, including providing market oversight and pursuing refunds 

of overcharges.
California State Auditor Report 2008-602 11

June 2009

The Evolution of California’s Electricity Market Structure

Under the restructured market system, which began operating in 

March 1998, the establishment of the PX and the ISO introduced 

new ways by which the utilities procured and delivered electricity 

for consumers. The large investor-owned utilities divested or 

sold off power plants and turned over the operational control of 

transmission lines to the ISO, allowing other companies to enter 

the new market and competition to arise. Investor-owned utilities 

were required to sell and purchase all of their electricity through 

the PX until March 2002 or until the CPUC ruled that they had 

recovered certain costs, whichever occurred first.2 Other entities, 

such as municipal utilities or rural irrigation districts, could also 

purchase electricity through the PX if they chose. Additionally, the 

ISO became the system operator responsible for monitoring and 

managing grid operations for the service areas of all three large 

investor-owned utilities. Further, because of industry restructuring, 

municipal utilities and rural irrigation districts had the option 

either to remain in control of balancing the electricity flow within 

their respective jurisdictions or to release that responsibility to the 

ISO. As Figure 2 shows, the ISO’s balancing authority area currently 

encompasses the service areas of all three large investor-owned 

utilities, Bear Valley Electric Service, and smaller municipal utilities 

and irrigation districts.

Of the several short-term markets that the PX operated, the 

day‐ahead market was the largest. In this market, buyers requested 

the amount of electricity that they anticipated needing for each 

hour of the next day and stipulated the prices that they were willing 

to pay. At the same time, sellers stated the amount of electricity 

that they could produce and the prices that they required for each 

of those hours. These bids established the market-clearing price 

at which all electricity was sold. Additionally, these market trades 

resulted in matched supply and demand schedules submitted to 

the ISO, which compared these schedules to the capabilities of the 

transmission system. If the ISO determined that the electricity 

providers had scheduled more electricity to flow across a certain 

transmission path than the lines could transmit—a situation 

known as congestion—the ISO rerouted the electricity through a 

different path, thus avoiding overloading the transmission system. 

In these instances, the ISO charged electricity suppliers and users 

congestion fees.

2 In an order dated December 15, 2000, FERC eliminated the State’s requirement that the 

investor-owned utilities use the PX to sell all of the electricity that they generated and to buy all 

of the electricity needed to serve their customers. In January 2001 the PX ceased operating.
California State Auditor Report 2008-602

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12

The ISO was also and continues to be responsible for procuring 

ancillary services for each day. Ancillary services are purchased 

for several different purposes, one of which is to balance the 

electric system in real time. For example, although the utilities 

and other providers estimate 24 hours in advance the gross levels 

of electricity that California consumers will demand and that the 

electricity providers will supply, in real-time demand can exceed 

supply to some degree and vice versa. The ISO monitors the 

real-time system functions and balances them by ordering increases 

or decreases in the amount of electricity supplied to the system. 

Such transactions are called imbalance energy purchases. If the ISO 

lets the differences between supply and demand become too great, 

the whole electric grid is at risk of crashing.

The other ancillary services that the ISO procures are electricity 

reserves used as a safety net in case a power generator or 

transmission line unexpectedly fails. These services include the 

capacity to produce electricity. The ISO purchases or reserves these 

ancillary services, which the ISO ranks according to the speed at 

which they can be made available if needed.

In the midst of the State’s energy crisis, which we will discuss 

later in this report, the short-term markets operated by the PX 

closed in January 2001. Subsequently, long-term power contracts 

initially secured by the State in many cases, provided an increasing 

amount of California’s electricity needs. However, the ISO 

continued to operate the real-time, ancillary services market to 

ensure the reliability of electrical services.

The Role of Regulators in the Current Market

Regulatory entities that currently play important roles in the 

electricity market include FERC, the CPUC, the Energy Commission, 

the California Air Resources Board (Air Resources Board), and the 

State Water Resources Control Board (Water Control Board).

The Federal Energy Regulatory Commission

FERC is the principal federal agency that, under the Federal Power 

Act, oversees the rates, terms, and conditions governing the 

interstate sales and transmission of wholesale power. In addition, 

it is FERC’s responsibility to assure that wholesale rates are just 

and reasonable and that they are not unduly discriminatory or 

preferential. Because California’s transmission system connects to 

systems in other states, allowing California to import and export 

power, FERC has some regulatory authority over the ISO. FERC 

reviews and approves the ISO’s rates and other filings covering 
California State Auditor Report 2008-602 13

June 2009

topics such as the structure of its governing board, access to the 

interstate electric grid, or the publication of information regarding 

the operation of the electric grid. FERC also grants permission for 

Western power generators to participate in California’s electricity 

market and to charge market-based wholesale rates for the 

electricity they sell. Finally, as a result of the federal Energy Policy 

Act of 2005, FERC established rules to prohibit electricity market 

manipulation and fraud.

The California Public Utilities Commission

The CPUC regulates the State’s privately owned utilities, which 

include all investor-owned utilities. The CPUC is charged with 

the following:

•	 Under AB 1890, implementing direct retail access, a program that 

allows consumers to choose to contract directly for electricity 

from a power supplier rather than purchase electricity from their 

local utility. However, as discussed in a later section, direct access 

was suspended in 2001.

•	 Regulating retail rates charged by investor-owned utilities.

•	 Ensuring retail power reliability.

•	 Overseeing mergers of investor-owned utilities.

•	 Implementing consumer protection and education programs 

about retail electricity services.

•	 Monitoring the market behavior of investor-owned utilities and 

contracts between these utilities and qualified generators.

The CPUC is also responsible for evaluating the economic 

need for additional transmission capacity and for reviewing the 

reasonableness of construction costs for ratemaking purposes once 

transmission construction is complete.

The California Energy Commission

Established by the Legislature in 1974, the Energy Commission 

is the State’s primary energy policy and planning agency, and it is 

responsible for the following:

•	 Forecasting future energy needs and keeping historical 

energy data.
California State Auditor Report 2008-602

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14

•	 Licensing thermal power plants that are 50 megawatts or larger. 

This process, generally referred to as siting, encompasses an 

analysis of all aspects of a proposed project, including need, 

public health and environmental impacts, safety, efficiency, and 

reliability. Plants smaller than 50 megawatts are licensed by 

city- and county-based agencies.

•	 Promoting energy efficiency through appliance and 

building standards.

•	 Developing energy technologies and supporting 

renewable energy.

•	 Overseeing programs that fund energy research.

The California Air Resources Board

In California, one of the principal environmental issues involved in 

generating and transmitting electricity relates to air quality. The 

Air Resources Board, established by the Legislature in 1967, is 

responsible for developing the State’s air pollution standards and 

for overseeing the operation of its 35 local air quality districts 

that implement state and federal clean air standards. Local 

areas that exceed federal and state standards for any of a number 

of identified pollutants are designated as non‐attainment areas 

and are subject to more stringent regulations.

One element of the Air Resources Board’s air quality control is 

emissions credits, which are also known as pollution credits. Power 

plant owners must obtain an annual allocation of credits per facility 

that allows for a certain level of emissions; although power plants 

emit many pollutants, the most significant are nitric oxides and 

nitrogen dioxides collectively referred to as NOx. As the plants 

run, their emissions are measured and their credits are depleted. 

However, all local air quality districts must adopt pollution credit 

banking programs that allow power plants and other entities to 

trade credits at market prices. Therefore, once a power plant uses 

all of its emissions credits, it must either purchase additional credits 

from another entity or restrict its electricity production. By allowing 

cleaner entities to trade their credits with those whose emissions 

exceed set standards, pollution levels overall are controlled, and no 

one industry is excessively penalized for its emissions levels.
California State Auditor Report 2008-602 15

June 2009

The State Water Resources Control Board

The Water Control Board is responsible for water allocation and 

water quality protection for the State. Some power plants are fueled 

by natural gas or nuclear reactors that use significant amounts of 

water to cool their systems and that discharge this water back into 

the environment, a practice that, among other things, kills fish and 

shellfish. Therefore, the Water Control Board’s regulations affect the 

operation of these plants.

Other Entities That Contribute to California’s Electric Industry

The California Independent System Operator

The ISO is responsible for managing the flow of electricity along 

approximately 80 percent of California’s electric grid. The nonprofit 

public-benefit corporation began operating in March 1998, when 

the wholesale electricity market began functioning in California.

The Department of Water Resources

The State’s Department of Water Resources (Water Resources) 

manages a portfolio of long-term power contracts with wholesale 

generators and of bond debts issued to pay for the contracts. In 

response to the energy crisis of 2000 and 2001, the governor and 

the Legislature authorized Water Resources to enter into these 

contracts on behalf of the large investor-owned utilities. Water 

Resources’ authority to enter into new contracts ended in 2003.

Scope and Methodology

California Government Code, Section 8546.5, authorizes the bureau 

to establish an audit program for identifying state agencies that are 

at high risk for potential waste, fraud, abuse, and mismanagement 

or that have major challenges associated with their economy, 

efficiency, or effectiveness. The law also authorizes the bureau to 

audit any state agency that it identifies as being at high risk and 

to publish related audit reports at least once every two years. This 

includes challenges that cut across programs or management 

functions at all state agencies or multiple state agencies: we refer 

to these as statewide issues. The considerations the bureau uses 

for determining high risk are set forth in the Appendix to the 

inaugural high-risk list published in the bureau’s report titled 

High Risk: The California State Auditor’s Initial Assessment 

of High‐Risk Issues the State and Select State Agencies Face, 
California State Auditor Report 2008-602

June 2009

16

Report 2006-601, May 2007. This report adds the production and 

delivery of electricity to the initial list of high-risk areas that the 

bureau identified.

Throughout this report, we cite information obtained from the 

Energy Commission, the CPUC, the ISO, Water Resources, 

and other agencies and entities. Other than confirming that 

the information appeared reasonable in the context of other 

information in our possession, we did not perform procedures to 

test the reliability of the data presented. Where possible, we relied 

on data from the Energy Commission, which is the State’s primary 

energy policy and planning agency, to perform our analysis.

In reviewing the factors that caused the energy crisis of 2000 

and 2001, the mitigating actions undertaken by the State and 

market participants, and the status of ongoing energy-related 

initiatives and programs, we interviewed various subject-matter 

experts working for the Energy Commission, the CPUC, the 

ISO, and Water Resources, and we obtained their feedback 

on this report. For example, we spoke to experts to verify our 

understanding of the factors that gave rise to the energy crisis 

of 2000 and 2001 and to obtain the status of long-term energy 

contracts managed by Water Resources. They were also helpful 

in identifying the major issues, critical documents, and data 

surrounding each of the identified risk areas.
California State Auditor Report 2008-602 17

June 2009

Analysis Results

Various Factors Contributed to the Energy Crisis 

of 2000 and 2001

A complex combination of factors contributed 

to the statewide energy crisis of 2000 and 2001, 

and some of these factors continue to pose 

concerns and to contribute to the decision by 

the Bureau of State Audits (bureau) to identify 

energy—and especially the production and 

delivery of electricity—as a high-risk issue for 

the State of California (State). For example, sharp 

fluctuations in the price of natural gas and reduced 

availability of electricity imports from the Pacific 

Northwest contributed to California’s energy crisis. 

Additionally, design flaws in the energy market, 

such as the manipulation of wholesale prices by 

generators and electricity brokers, played a role in 

the energy crisis. The text box outlines these and 

other circumstances that factored into California’s 

difficulties involving the generation, transmission, 

and delivery of electricity.

The various problems that played parts in the 

energy crisis included an increasing demand for 

electricity by residents and businesses, inadequate 

generation of electricity within the State, and 

inadequate transmission capacity to transport 

electricity within the State. Because of population 

expansion and rapid economic growth, electricity 

demand within the State increased by more than 

3 percent over the prior year in both 1999 and 2000. 

However, the California Energy Commission 

(Energy Commission) had received and approved 

few power plant applications in the early 1990s, 

apparently due in part to a combination of excess 

supply at the time and uncertainty on the part of 

the investor-owned utilities, or privately owned utilities, about the 

potential effects of energy market restructuring. As a result, only 

three generating plants larger than 50 megawatts (defined in the 

text box on the following page) were built in the State from 1996 

to 2000, and these did not provide the additional electricity needed 

to meet the State’s increased demand. Delays in the siting process 

also postponed the opening of power plants that could have helped 

meet electricity needs. Limited transmission capacity in certain 

areas of the State, such as the San Francisco peninsula, further 

exacerbated the increased but unmet need for electricity. For 

example, due to congestion, the primary transmission connection

Factors That Contributed to California’s Energy 

Crisis During 2000 and 2001

General factors in higher energy prices and shortages:

•	 California’s electricity demand grew, but the number of

new power plants and transmission lines did not keep up 

with that growth.

•	 Transmission congestion made it difficult to transport

electricity to locations that needed it most.

•	 Below average rainfall in the Pacific Northwest decreased

hydroelectric power available for import into California.

•	 Population growth in neighboring states increased

demand for power and reduced electricity available for 

import into California.

•	 Power generators were subjected to increased costs,

including the price of natural gas.

Specific problems caused by design flaws in California’s 

restructured market:

•	 Investor-owned utilities could not sign long-term power

contracts that would have provided some protection 

against the increases in wholesale electricity prices.

•	 Short-term market structure, particularly the day-ahead

and real-time markets, permitted the manipulation 

of prices by wholesale electricity generators and 

electricity brokers.

•	 The price freeze on retail prices meant investor-owned

utilities could not recover higher-than-expected costs of 

wholesale electricity.

Sources: Bureau of State Audits’ analysis and the Public Policy 

Institute of California.
California State Auditor Report 2008-602

June 2009

18

between Northern and Southern California could 

not transmit the volume of electricity that 

Northern California needed in January 2001, and 

this situation contributed to the rolling blackouts 

that ultimately occurred.

Additionally, other dynamics outside the State’s 

direct control further decreased the available 

supply of electricity and contributed to an 

increase in its wholesale cost. A report published 

by the Public Policy Institute of California3 (policy 

institute) noted that dry winters in the northwestern states reduced 

the availability of hydroelectric power that the State could import. 

Further, the report concluded that neighboring states grew at 

rapid rates, consuming power that otherwise might have gone to 

California. Between 1988 and 1998, Nevada’s electricity demand 

grew by an average of 6.2 percent annually, and Arizona’s demand 

grew 3.7 percent annually. Moreover, the policy institute report 

cites additional costs to generators that contributed to a general 

escalation in wholesale electricity prices. These costs arose from 

such circumstances as unprecedented volatility and increases in 

the price of natural gas in California, which was used to generate 

38 percent of the State’s electricity in 2000, and higher costs for air 

pollution permits, which air quality regulators require of generators 

that run the higher polluting plants.

In addition to the problems previously described, California’s 

restructuring efforts led to potentially avoidable market design 

flaws that contributed to record wholesale electricity prices and the 

energy crisis. Specifically, the initial decision by the California Public 

Utilities Commission (CPUC) to restrict California’s investor-owned 

utilities from using long-term contracts—agreements that 

specify that a purchaser can buy a certain amount of electricity 

in the future at a predefined price—hindered these utilities from 

absorbing shocks and volatility in the wholesale price of electricity. 

Long-term contracts can potentially give investor-owned utilities an 

effective hedge against price fluctuations in short-term markets by 

providing price certainty in the future as well as supply availability. 

Various considerations caused the State to require the three large 

investor-owned utilities—Pacific Gas and Electric Company 

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

Company—to make all of their energy purchases in the short-term 

markets instead of through contracts. One such consideration was 

that this purchasing method made the utilities’ transactions easier to 

monitor for regulators. Further, markets need sufficient participation 

3 Christopher Weare, The California Electricity Crisis: Causes and Policy Options (Public Policy Institute 

of California, 2003).

Megawatt:

One megawatt equals 1 million watts or 1,000 kilowatts, 

which is enough electricity to meet the instantaneous 

demand of roughly 750 homes at once. (The number of 

homes fluctuates because electricity demand changes 

based on the season, the time of day, and other factors.)

Source: California Independent System Operator’s Web site.
California State Auditor Report 2008-602 19

June 2009

to function efficiently. Forcing investor-owned utilities into the 

short-term markets helped ensure sufficient participation and 

the market’s continued financial viability.

In contrast to California’s focus on short-term markets for 

electricity, other states and countries have taken a different 

approach to restructuring. Energy providers in these states and 

countries used contracts to purchase most of the electricity used; 

energy providers purchased only 10 percent to 20 percent of their 

power in short-term markets.

Unfortunately, the structure of California’s electricity markets 

allowed for price manipulation. Evidence suggests that wholesale 

electricity generators and brokers sought to increase prices further 

by withholding available power from the markets. For instance, 

an analysis by the U.S. Government Accountability Office found 

that California’s highest electricity prices in 2000 occurred during 

periods of low demand; however, one would expect to see the highest 

prices during periods of high demand. Also, the policy institute 

report notes that it is debated whether generators intentionally 

took power plants off-line to withhold supply and drive prices up 

between November 2000 and May 2001—during the peak of the 

energy crisis. At the time, generators claimed that power plants were 

out of service for maintenance. Complicating its operation of the 

electric grid, the California Independent System Operator (ISO) had 

no authority to control the scheduling of power plant outages for 

maintenance. Conversely, in an effort to drive down wholesale prices, 

the three large investor-owned utilities—which before restructuring 

had been successful historically in forecasting consumers’ demand 

within 2 percent to 3 percent—allegedly underscheduled the volume 

of electricity needed to service their customers in the day-ahead 

market, leaving the utilities’ more exposed to higher prices in the 

real-time market.

Because of a freeze on retail electricity rates imposed by state law, 

the two largest investor-owned utilities soon could not recoup the 

increased costs of electricity that they were buying for their 

customers. As a result, PG&E and Southern California Edison 

began defaulting on their bills, and PG&E filed for bankruptcy in 

April 2001. Various credit-rating firms took note of the three large 

investor-owned utilities’ worsening financial condition and, in 

January 2001, downgraded the utilities’ credit ratings to junk bond 

status, that is, at higher risk of defaulting on debts. Such actions 

eliminated the ability of PG&E and Southern California Edison to 

enter into contracts, or indeed to purchase any electricity at all. 

In December 2000 the Federal Energy Regulatory Commission 

(FERC) negated the CPUC requirement that the three large 

investor-owned utilities purchase their power through the markets 

Evidence suggests that wholesale 

electricity generators and brokers 

sought to increase prices further by 

withholding available power from 

the markets.
California State Auditor Report 2008-602

June 2009

20

of the Power Exchange (PX), which largely ceased to operate in 

January 2001. (See this report’s Introduction for more information 

about the PX and its role in the electricity markets.)

Mitigating Actions Have Reduced the Likelihood of Another 

Energy Crisis

In the wake of rolling blackouts and high prices, key state entities 

and participants in the electricity market took various actions to 

mitigate the electric system imbalances and the specific design 

problems that the restructured market revealed had contributed 

to the crisis. To stabilize prices and reduce exposure to the price 

volatility that occurred in the short-term markets, the CPUC 

allowed greater use of long-term contracts. In addition, the 

Legislature empowered the Department of Water Resources (Water 

Resources) to enter into long-term contracts to buy power from 

wholesalers on behalf of the three large investor-owned utilities, 

which were not in a financial position to enter into contracts. 

This was largely due to the retail rate freeze that was imposed by 

law. Additionally, regulators began ensuring that these utilities 

procured enough electricity to meet demand forecasts. Market 

participants also took actions to bring more electricity generation 

online in California, to improve the transmission system to reduce 

congestion, and to implement programs to reduce the overall 

demand for electricity. Market observers suggest that together these 

actions have expanded energy infrastructure and decreased the risk 

of another energy crisis.

On Behalf of Investor‐Owned Utilities, Water Resources Entered Into 

Long‐Term Electricity Contracts to Stabilize the Price of Electricity

Taking a major step to alleviate the energy crisis and to stabilize the 

price of electricity, the State entered into long-term contracts with 

companies that supply electricity, thus moving away from its directive 

that California’s energy providers must purchase almost all electricity 

through the short-term markets. In doing so, the State retreated from 

several of the key features of the restructured market design. During 

the energy crisis, the CPUC granted emergency authorizations 

for the two largest investor-owned utilities to enter into long-term 

contracts. However, in January 2001, it became increasingly 

apparent that the investor-owned utilities would have difficulties 

purchasing electricity. At that time, the governor proclaimed 

a state of emergency. In February 2001 the governor approved 

legislation that authorized Water Resources to enter into long-term 

contracts to purchase electricity on behalf of the financially 

stressed investor-owned utilities. Subsequently, Water Resources 

entered into 57 long-term contracts in 2001 and 2002 at a total 

The Legislature empowered 

Water Resources to enter into 

long-term contracts to buy power 

from wholesalers on behalf of the 

three large investor-owned utilities.
California State Auditor Report 2008-602 21

June 2009

cost of approximately $42.6 billion over 10 years. Although Water 

Resources’ authority to enter into these long-term contracts expired 

in January 2003, many of these contracts remain in effect today. 

As this report discusses in a later section, the large investor-owned 

utilities currently enter into their own long-term contracts to make 

up the difference in the electricity provided to retail consumers under 

the remaining Water Resources’ contracts.

According to the director of the ISO’s department of market 

monitoring (monitoring director), the State’s long-term contracts 

and subsequent contracts entered into by the large investor-owned 

utilities have provided several important market benefits, the most 

important of which are a reduction in the large investor-owned 

utilities’ exposure to price volatility in the short-term markets, 

a decrease in the wholesale generators’ incentive to manipulate 

prices, and an increase in investment in new power plants. The 

monitoring director concluded that the use of long-term contracts 

shifts the financial risk from the large investor-owned utilities to 

the suppliers and reduces the incentive for wholesale generators 

to withhold electricity generation. Additionally, the monitoring 

director explained that with long-term contracts in place, the 

volume of electricity sold in the short-term markets becomes so 

small that it is not profitable for wholesale generators to attempt to 

manipulate prices. Furthermore, the monitoring director noted that 

long-term contracts provide incentives for wholesale generators 

to better maintain their power plants because the generators are 

aiming to fulfill their contracts in the least costly manner. This 

improvement in maintenance may also have reduced the number of 

forced outages of power plants.

A Cooperative Regulatory Approach Helps Ensure That Utilities Acquire 

Adequate Power Supplies to Meet Forecasted Demand

Further contributing to the stability of the energy market, under 

State law, CPUC now requires that investor-owned utilities plan 

and contract for sufficient power to meet forecasted peak demand 

plus a reserve margin, known as resource adequacy. According to 

the CPUC, it currently requires the large investor-owned utilities, 

among others, to demonstrate that they have contracted for power 

to meet their anticipated demand for electricity, plus an additional 

15 percent to account for forecast error and generation outages, 

over yearly and monthly intervals. The ISO also indicated that 

if investor-owned utilities cannot demonstrate that they have 

enough electricity available to meet the CPUC resource adequacy 

requirements, the ISO can intervene and procure additional 

supplies to ensure that an adequate volume of electricity is flowing 

through the grid to maintain stability and reliability of services 

to consumers.

The use of long-term contracts 

shifts the financial risk from the 

large investor-owned utilities to 

suppliers and reduces the incentive 

for wholesale generators to 

withhold electricity generation.
California State Auditor Report 2008-602

June 2009

22

As part of the resource adequacy program, the Energy 

Commission’s deputy director for the electricity supply analysis 

division explained that the Energy Commission ensures that the 

demand forecasts that the investor-owned utilities use for resource 

adequacy are consistent with the Energy Commission’s forecasts. 

Furthermore, according to the Energy Commission, under state law 

it also provides oversight for resource adequacy implementation by 

the municipal utilities and irrigation districts. The CPUC and the 

Energy Commission indicated that they require the investor-owned 

and municipal utilities to develop and submit procurement plans, 

which detail how utilities expect to meet customer needs for the 

next 10 years. According to the CPUC, its long-term procurement 

plans program requires utilities to forecast future electric capacity 

and energy needs and develop a plan that ensures electricity 

needs will be met. Additionally, the CPUC indicated that the 

plans, which are updated every two years, include building new 

utility-owned power plants, entering contracts that support the 

building of new independently owned power plants, and entering 

into short-term, intermediate-term, and long-term contracts 

with existing power plants. According to Energy Commission 

staff, it takes about five years to plan and bring online new power 

plants or expansions of existing plants and seven years to plan 

and construct transmission infrastructure, demonstrating the 

importance of estimating demand at least 10 years ahead and then 

planning accordingly.

Other forecasting efforts assist in providing additional assurance 

that the State will have enough electricity in the future. For 

instance, according to the Energy Commission, the ISO prepares 

forecasts independently from those prepared by the Energy 

Commission and focuses on its balancing authority area, whereas 

the Energy Commission focuses on the entire state. According to 

Energy Commission staff, the two entities meet a couple of times 

a year to review each other’s energy forecasts and to discuss and 

understand differences between the forecasts, such as disparities 

in economic assumptions or identified congestion constraints. To 

improve the accuracy of the forecasts, the Energy Commission 

indicated that it is working to develop a model that will incorporate 

into its long-term forecasting expected benefits from energy 

efficiency programs and contract requirements.

Additionally, since 2001 the Energy Commission has issued 

a summer electricity supply and demand outlook report that 

provides an assessment of the electric system’s capability to meet 

peak electricity demand in the summer months in California and 

in the smaller geographic regions overseen by the ISO. According 

to the Energy Commission’s deputy director for the electricity 

supply analysis division, the supply-and-demand outlook report for 

summer electricity is an early warning projection for the coming 

The Energy Commission is 

working towards incorporating 

into its long‐term forecasting 

expected benefits from energy 

efficiency programs and 

contract requirements.
California State Auditor Report 2008-602 23

June 2009

summer months and merely alerts the Energy Commission to 

a looming planning failure; it can do little to prevent a failure. 

However, it can be used to make public appeals for conservation or 

to reschedule planned outages.

New Generation and Transmission Upgrades Improve the Flow 

of Electricity

Significant additions in the energy infrastructure have taken place 

since the energy crisis that helps to reduce the risk that another 

energy crisis may occur. However, as a later section explains, what 

was gained in electricity supplies by building new power plants 

during the last 10 years may be somewhat offset by the need to 

replace environmentally harmful and aging power plants in the near 

future and by the difficulties that the State faces in doing so.

During the last decade the Energy Commission has approved new 

power plants. According to the Energy Commission’s reports on 

the status of energy facilities, as of May 2009, it had approved 

69 power plants. These approved plants have the capacity to 

produce more than 25,000 total megawatts of power; however, as 

of May 2009, only 42 of these power plants were online. As Table 1 

on the following page indicates, the facilities brought online have 

the capacity to produce just over 14,200 total megawatts. Although 

energy providers have retired some power plants, the increase in 

megawatts brought online has resulted in roughly 9,200 megawatts 

of power available to meet electricity demands. Further, according 

to the Energy Commission’s reports on the status of energy facilities 

as of May 2009, power plants currently under construction will 

have the capacity to generate nearly 2,400 megawatts. An additional 

6,600 megawatts could be generated from approved plants for 

which construction has not begun or is on hold due to unfavorable 

markets or unavailable financing. Additionally, power plants with 

applications pending before the Energy Commission could have 

the capacity to produce over 10,500 megawatts if approved and 

placed online.

According to the ISO’s monitoring director, California has made 

significant strides in adding to its electrical infrastructure since the 

energy crisis. For example, the monitoring director explained that 

from the end of the energy crisis in 2001 through 2007, the ISO 

gained approximately 15,800 megawatts to its balancing authority 

area, or the region in which it has the authority to balance the 

electricity flow across transmission lines. This figure represents an 

increase of approximately 39 percent over the 41,000 megawatts of 

estimated available generation in 2000. Additionally, the monitoring 

director concluded that new electricity generation throughout the 

West provides additional opportunities for California to import 
California State Auditor Report 2008-602

June 2009

24

power when needed to meet peak demands. Further, in its 2008 

Annual Report on Market Issues and Performance, the ISO projects 

that generation additions in Southern California will just keep 

pace with consumer demand and unit retirements. However, after 

the ISO accounts for consumer demand and unit retirement, it 

forecasts that Northern California will see a larger increase in new 

electricity generation. Thus, the supply shortages that contributed 

to the energy crisis in 2000 and 2001 are not as likely to reoccur.

Table 1

Maximum Generating Capacity of California Power Plants Brought Online or 

Retired From 1998 Through 2009 

(In Megawatts)

Year

Megawatts 

Brought Online

Megawatts 

Retired*

Net Change in 

Megawatts

1998 0 1 (1)

1999 0 56 (56)

2000 0 1 (1)

2001 1,914 39 1,875

2002 2,504 807 1,697

2003 3,893 2,122 1,771

2004 0 328 (328)

2005 2,584 1,320 1,264

2006 2,015 219 1,796

2007 177 0 177

2008 93 0 93

2009† 1,050 0 1,050

Totals 14,230 4,893 9,337

Source: The California Energy Commission’s (Energy Commission) energy facility status reports as of 

May 2009.

* According to the Energy Commission, retired generally refers to generation from those plants 

that will never come back online (that is, components of the plant have been disassembled and 

removed for resale or scrap).

† The data presented for calendar year 2009 represents megawatts brought online or retired 

through May 1, 2009.

According to the ISO, in addition to the construction of new power 

plants, improvements to California’s key transmission lines are 

complete. The ISO’s monitoring director noted that the capacity 

on frequently congested transmission lines in the ISO’s balancing 

authority area has increased by approximately 4,600 megawatts. 

Notably, in 2004 and 2005, utilities completed upgrades to the 

main transmission lines that allow electricity to move between 

California’s southern and northern regions—regions that 

experienced significant congestion during the energy crisis, thus 

causing blackouts.
California State Auditor Report 2008-602 25

June 2009

New Programs Aim to Reduce Energy Consumption, Especially During 

Peak Demand

Because development of electricity-generating capacity must 

consider peak demand and because the addition of new system 

capacity is time-consuming and expensive, state entities and other 

participants in the electricity market are also working to implement 

programs, such as conservation and energy efficiency rebates, to 

reduce electricity usage. In particular, the Energy Commission, 

the ISO, and the CPUC aim to reduce usage during peak demand 

periods, or the hours when most consumers use electricity and 

when electricity costs are highest. To accomplish this goal, both 

investor-owned and municipal utilities offer demand response 

programs (demand response) that provide incentives to businesses 

and consumers when they reduce their consumption when asked 

during certain periods. Both the Energy Commission and the 

CPUC agree that demand response can reduce electricity use 

during peak periods when the least efficient generation occurs, 

which may thereby reduce greenhouse gas and other air emissions. 

Additionally, according to the CPUC, it has set timetables to 

introduce dynamic pricing programs that reflect high and low 

periods of usage for large commercial and industrial customers. 

In fact, according to the Energy Commission, the State has a 

goal of reducing peak usage by 5 percent through the use of 

demand response.

Even outside of peak demand periods, state agencies and market 

participants are working to reduce total demand through 

conservation and energy efficiency programs. Assembly Bill 2021 

(AB 2021), Statutes of 2006, set a statewide goal of reducing total 

forecasted electricity consumption by 10 percent over the next 

decade. Under AB 2021, the Energy Commission and the CPUC 

are responsible for setting annual statewide efficiency targets in a 

public process using the most recent targets from investor-owned 

and publicly owned utilities. To increase energy efficiency, the 

Energy Commission sets building and appliance standards, and 

the utilities and public agencies run programs that promote 

energy conservation. For example, according to the CPUC, 

the energy efficiency programs run by the investor-owned utilities 

between 2006 and 2008 reduced the need for approximately 

1,500 megawatts of electric-generating capacity, which is the 

equivalent of three large power plants, through hundreds of 

targeted programs aimed at encouraging consumers to invest 

in efficient buildings and appliances. In addition, new efficiency 

standards for buildings will go into effect on August 1, 2009. Finally, 

California’s Flex Your Power campaign is a statewide marketing 

and outreach effort operating since 2001 to encourage energy 

Demand response programs 

provide incentives to businesses 

and consumers when they reduce 

their consumption when asked 

during certain periods, such as 

during peak periods when the least 

efficient generation occurs.
California State Auditor Report 2008-602

June 2009

26

conservation. The Flex Your Power Web site directs consumers to 

various rebate and incentive programs offered by the utilities and 

other organizations.

The Need to Replace or Retrofit Aging and Environmentally Harmful 

Power Plants May Cause Significant Reductions in Electricity Supplies

Although the State is working to increase electricity generation and 

transmission, aging and environmentally harmful power plants that 

supply a significant portion of California’s electricity capacity may 

need to undergo expensive retrofittings of their cooling systems or 

shut down. At the same time, various issues may delay or prevent 

the construction of new power plants or updates to existing 

plants. The uncertainty about the power plant owners’ ability or 

desire to replace the cooling systems at existing power plants poses 

a high risk to the State because loss of electricity supplies could 

compromise the reliability of electrical services. In particular, 

Southern California may bear the greatest burden because many of 

the aging and environmentally harmful power plants that may be 

forced to retrofit or close are in that region, and it lacks adequate 

transmission capacity to allow the import of sufficient electricity 

from other sources on peak demand days. Nonetheless, a recent 

court order required the South Coast Air Quality Management 

District (South Coast Air District) to halt certain activities to enable 

new power plant construction and upgrades in this region.

A Proposed Statewide Policy May Force Certain Power Plants to Close

The State Water Resources Control Board (Water 

Control Board), which is responsible for 

water allocation and water quality protection 

for the State, has proposed a statewide policy to 

implement the 1977 federal Clean Water Act, as 

amended, that controls the harmful effects of 

water intake structures for once‐through cooling

on marine life. The Water Control Board and 

the California Environmental Protection Agency 

(Cal/EPA) have pointed out that California power 

plants that use once-through cooling damage 

over 79 billion fish and other organisms annually. 

In June 2006 the two agencies issued a scoping document that 

presented information on a proposed statewide policy related to 

complying with the federal Clean Water Act regulations. In the 

scoping document, the two agencies identified the 21 power plants 

in California that would be subject to the federal act. In a letter dated 

September 2006, the ISO provided comments to the Water Control 

Board related to the proposed statewide policy indicating that it had 

Once-through cooling:

A process that uses seawater to remove waste heat 

produced during power generation and then discharges the 

heated water back into the environment. The heated water 

can affect the marine environment. Additionally, marine 

organisms may be killed or injured when they are pulled

into the power plant cooling system.

Source: California Energy Commission.
California State Auditor Report 2008-602 27

June 2009

reviewed the list of power plants subject to the federal Clean Water 

Act, and the ISO offered the following observations: “The policy 

will essentially require existing power plants to retrofit to a cooling 

tower or they will no longer have a valid water permit and be forced 

to retire. Either scenario has a negative impact on the amount of 

generation available to meet the electricity needs of California. In 

the case of a cooling system retrofit, the facilities will produce less 

electricity, be less efficient, and may have to run longer to recover 

the retrofit costs. Alternatively, if the power plant retired before new 

generation is available, it could result in adverse impacts on public 

health and safety and the economy due to insufficient generation to 

meet all the electricity needs of California.”

In March 2008 the Water Control Board and Cal/EPA issued a 

second scoping document that updated the 2006 document and 

took into consideration some federal regulatory changes to the 

Clean Water Act. In this version, the agencies indicated that they 

intended the document to give the public a preliminary proposal 

for a statewide policy to implement the Clean Water Act. The 

Energy Commission provided a summary of the Water Control 

Board and Cal/EPA’s proposal in its 2008 Integrated Energy Policy 

Report, which indicated that the proposed policy calls for the 

phased elimination of once-through cooling between 2015 and 2021 

and that without alternative mitigation measures, accomplishing 

this goal will require the retrofitting, repowering, replacement, 

or retirement of 19 power plants, which currently represents 

nearly 40 percent of the State’s generating capacity.4 Although the 

Water Board and Cal/EPA indicated that these 19 power plants 

actually produced only 20 percent of the State’s electricity in 2005, 

both the ISO and the Energy Commission agree that some of 

these plants are essential to ensuring reliable electricity service 

throughout California. Figure 3 on the following page shows the 

locations and generating capacity of the power plants that use 

once-through cooling.

Finally, to further add to the concerns expressed above by 

the Energy Commission and the ISO, a number of energy 

agencies—including the Energy Commission, the CPUC, and 

the ISO—believe that power plant owners, concerned about the 

ability to recoup the substantial investments necessary to retrofit or 

replace their power plants, will opt to retire their existing facilities 

rather than to invest the funds needed to pay for the new

4 Two power plants have closed since the 2006 proposal identified 21 power plants.
California State Auditor Report 2008-602

June 2009

28

Figure 3

Power Plants Affected by Proposals to Retire Aging and Once-Through 

Cooling Plants

Humboldt Bay—107 megawatts (mw)

Pittsburg—1,332 mw‡

Contra Costa—680 mw

Potrero—207 mw

Moss Landing—2,484 mw§

Morro Bay—600 mw

Diablo Canyon—2,232 mw Cool Water—727 mw

Scattergood—803 mw

El Segundo—670 mw

Harbor—227 mw

Haynes—1,606 mw*

Alamitos—1,970 mw

Huntington Beach—880 mw†

Redondo Beach—1,343 mw

Olive—110 mw Grayson—198 mw

Broadway—75 mw

Etiwanda—666 mw

San Onofre—2,246 mw

Ormond Beach—1,613 mw

Mandalay—435 mw

Encina—951 mw

South Bay—696 mw

El Centro—132 mw

Once-through cooling—6,795 megawatts

Agingll—2,590 megawatts

Agingll and uses once-through cooling—13,605 megawatts

Source: California Energy Commission.

Note: See page 26 for a definition of once-through cooling.

* The total megawatts for the Haynes power plant includes 560 megawatts from units that use 

once-through cooling, but are not aging.

† The total megawatts for the Huntington Beach power plant includes 450 megawatts from units 

that use once-through cooling, but are not aging.

‡ The total megawatts for the Pittsburg power plant includes 682 megawatts that are from units 

that are aging, but do not use once-through cooling.

§ The total megawatts for the Moss Landing power plant includes 1,080 megawatts that use 

once-through cooling, but are not aging.

ll Built before 1980 and larger than 10 megawatts.
California State Auditor Report 2008-602 29

June 2009

technology. In a May 2008 letter to the Water Control Board, the 

Energy Commission reiterated that although it supports efforts 

to reduce the environmental impacts of once-through cooling, it 

is concerned that a majority of the affected plants are located in 

areas that would have insufficient capacity to assure reliable electric 

service during periods of extreme summer peak demand if any 

more than minimal amounts of capacity were to be retired. In the 

same letter, the Energy Commission also indicated its support of 

a statewide task force to address these reliability concerns and to 

prevent disruptions of the State’s electrical power supply.

Since the first proposal for a statewide policy in 2006 related to the 

once-through cooling process, various stakeholders have studied 

the potential costs and timelines for retrofitting or replacing the 

power plants that use once-through cooling. More specifically, 

governmental agencies and organizations representing such 

stakeholders as environmental groups, power plant owners, and 

consumer advocacy organizations have commissioned studies to 

examine the financial costs and impacts of eliminating electricity 

supplies generated by power plants that use once-through cooling. 

For example, the ISO performed a study that assessed power 

plant owners’ preliminary plans for retiring or retrofitting their 

affected facilities and identified the impacts these changes would 

have on the electric grid. Another organization representing the 

electric industry performed a study that examined the scientific 

and technical issues related to phasing out once-through cooling, 

including estimating the costs to retrofit the existing plants. Finally, 

according to the external affairs manager with the ISO, the CPUC, 

the Energy Commission, and the ISO are working together with the 

Water Control Board to develop their recommendations and a 

schedule as to how the Water Control Board should implement 

its proposed policy related to phasing out the use of once-through 

cooling. The external affairs manager also indicated that the 

Water Control Board plans to issue a revised draft policy in 

July 2009, which will contain as an appendix an implementation 

plan and a compliance schedule developed by the ISO, the Energy 

Commission, and the CPUC. He believes the Water Control Board 

expects to adopt the policy by the end of the year.

Moreover, the Energy Commission also classifies many of the power 

plants that rely on once-through cooling as aging power plants, 

for which, in its 2005 Integrated Energy Policy Report, the Energy 

Commission recommended retirement. Figure 3 shows the power 

plants that use the once-through cooling process; some of these 

are also classified as aging power plants. According to information 

provided by the Energy Commission and the Water Control Board, 

the aging power plants typically are more than 30 years old, use 

older less efficient technologies, have higher rates of pollution, and 

are expensive to operate. In its 2005 and 2007 Integrated Energy 

Aging power plants typically are 

more than 30 years old, use older 

less efficient technologies, have 

higher rates of pollution, and are 

expensive to operate.
California State Auditor Report 2008-602

June 2009

30

Policy Reports, the Energy Commission recommended the orderly 

retirement of the aging power plants throughout California, a 

process that raises additional concerns about the reliable, affordable 

delivery of electricity.

Replacing Once‐Through Cooling and Aging Power Plants in Southern 

California Presents Additional Challenges

The Water Control Board’s proposed policy to shut down or 

replace the once-through cooling and aging power plants will be 

particularly challenging for Southern California. More specifically, 

a number of factors, including air quality requirements and a court 

ruling, provide obstacles to the power plant owners that want either 

to retrofit or to replace the aging power plants or those that use the 

once-though cooling process in Southern California.

The South Coast Air District is the air pollution control agency for 

Orange County and the urban portions of Los Angeles, Riverside, 

and San Bernardino counties. As one of the smoggiest regions in 

the nation, this area is also subject to stringent local air quality 

requirements. To obtain an operating permit from the South Coast 

Air District, the owner of any facility that will release pollutants 

into the air must demonstrate that the facility has the required 

number of emissions credits. The purpose of an emissions credit 

process is to ensure that new facilities do not increase pollution 

levels and reduce air quality in a region. Thus, before a facility that 

generates air pollution begins operating, it must obtain a sufficient 

number of emissions credits to offset the anticipated pollution that 

the facility will emit.

In 1990 the South Coast Air District established a priority reserve 

bank of emissions credits that it awarded to entities that serve a 

public interest, such as hospitals and police facilities. In response to 

concerns about the need to construct new power plants in Southern 

California, in 2007 the South Coast Air District added power plants 

to the list of entities eligible to receive emissions credits from the 

reserve bank. However, this action was successfully challenged in 

California Superior Court as it relates to the sufficiency of the South 

Coast Air District’s environmental analysis and the district’s addition 

of power plants to its list of those eligible to receive emissions credits 

from its bank. Specifically, a July 2008 trial court ruling found that the 

California Environmental Quality Act (CEQA) analysis that the South 

Coast Air District prepared was inadequate for a number of reasons. 

According to the Energy Commission’s February 2009 staff paper on 

this topic, the court stated that the South Coast Air District had failed 

to perform an adequate CEQA analysis to evaluate the potential 

impacts of the power plants that proposed to use priority reserve 

credits. The Energy Commission also stated that the court decision 
California State Auditor Report 2008-602 31

June 2009

indicated that a sufficient environmental document would require 

significant new analysis that the South Coast Air District believes it 

cannot reasonably provide. Moreover, according to the South Coast 

Air District, the court decision invalidated how the South Coast Air 

District accounts for the emissions credits that are available in its 

reserve bank. Consequently, in January 2009, the South Coast Air 

District issued a moratorium on permits to construct or operate 

power plants that require air emissions credits from the reserve bank.

In addition to the moratorium on any new projects, according to 

the South Coast Air District, the court’s ruling could also invalidate 

any permits issued since the South Coast Air District added power 

plants to the list of entities eligible to receive emissions credits from 

the reserve bank. According to the Energy Commission, seven 

power plants are currently going through the Energy Commission’s 

licensing process, and the South Coast Air District’s problem 

with its reserve bank’s emissions credits will affect this process. 

Data provided by the Energy Commission indicates that if these 

seven power plants are constructed, they will potentially generate 

more than 4,300 megawatts of electricity, offsetting some of the 

7,500 megawatts of power that will be lost when the aging and 

once-through cooling plants close.

At this time, according to the South Coast Air District, it is issuing 

permits to construct new power plants only to those entities that 

can provide or purchase their own emissions credits because, as 

previously described, the South Coast Air District is unable to 

release any emissions credits held in its reserve bank. If investors 

that desire to construct power plants in this area are unable to 

provide their own emissions credits, their next option is to attempt 

to purchase them on the open market; however, according to the 

South Coast Air District these credits are scarce and can be very 

expensive. In fact, the South Coast Air District estimates the cost 

to purchase emissions credits for a power plant could be between 

$100 million and $200 million. According to the South Coast 

Air District, between 2000 and 2008, the average market price 

has increased by over 3,700 percent. In other words, the price has 

risen from an average of $3,860 per pound per day of emissions to 

$148,760 per pound per day. Further, as of March 2009, emissions 

credits sold for as high as $320,000 per pound per day, an amount 

that is more than double the average 2008 price. If power plant 

operators can purchase the necessary emissions credits to bring 

additional power online, according to the Energy Commission, the 

current prices would contribute significantly to the cost of the new 

plant itself, which electricity providers would pass on to consumers 

in the form of electricity rate increases.

Early in 2009 the South Coast Air 

District issued a moratorium on 

permits to construct or operate 

power plants that require air 

emissions credits from the 

reserve bank as a result of a trial 

court ruling.
California State Auditor Report 2008-602

June 2009

32

Further contributing to the problem associated with replacing 

electricity supplies potentially lost in the South Coast Air District is 

the fact that according to the Energy Commission this region also 

lacks sufficient transmission capacity to allow it to import electricity 

from other areas; thus, unless additional high-voltage transmission 

lines are constructed, most of the replacement power plants must 

be built in the same general areas as the existing power plants. As 

we discuss in a later section, constructing new transmission lines 

is particularly challenging in part because multiple agencies may 

be involved in providing regulatory approval and oversight for 

constructing new transmission lines. Additionally, local opposition 

and environmental reviews can cause additional delays. The Energy 

Commission reported it might be difficult to build sufficient new 

transmission capacity before the 2015 deadline the Water Control 

Board recommended in its proposed policy to require power plant 

owners to discontinue using the once-through cooling process.

Large Investor-Owned Utilities Have Secured Long-Term Contracts as 

Water Resources’ Role Phases Out, but Some Uncertainty Remains

Water Resources played a critical role in providing electricity during 

the energy crisis; however, as the contracts it entered into during 

that time expire, the importance of its role has been declining, 

and efforts are currently under way to return all responsibility for 

supplying electricity to the investor-owned utilities, about five years 

prior to the expiration of the last of Water Resources’ long-term 

contracts. As Table 2 depicts, Water Resources is managing a 

portfolio worth approximately $8.9 billion. According to data 

provided by Water Resources, it has 26 contracts that are still in 

effect. These long-term contracts are expected to supply roughly 

23 percent of the large investor-owned utilities’ electricity needs 

in 2009. Although the utilities have been able to secure sufficient 

supplies of electricity through their own contracts to meet the 

balance of their customers’ demand, there is still uncertainty as 

to whether the utilities will continue to be in a position to secure 

an adequate supply. Further, efforts led by a group representing 

electricity suppliers and various private and public electricity 

consumers to again allow direct access—an option that enables 

customers to choose an electricity provider other than their default 

utility—creates additional uncertainty within the electricity market.

Overall Electricity Supplied by Water Resources Is Declining

As we discussed previously, urgency legislation passed during the 

energy crisis earlier in the decade allowed Water Resources to enter 

into long-term contracts to purchase and supply electricity on 

behalf of the State’s large investor-owned utilities, which were not

According to the Energy 

Commission, it might be difficult to 

build sufficient new transmission 

capacity before the 2015 proposed 

deadline requiring power plant 

owners to discontinue using the 

once-through cooling process.
California State Auditor Report 2008-602 33

June 2009

Table 2

The Department of Water Resources’ Remaining Long-Term 

Electricity Contracts

Year

Long‐Term

Contract Capacity* 

(in megawatts)

Value* 

(Dollars in 

billions)

2009 8,900 $3.6

2010 7,600 2.9

2011 5,500 2.0

2012 through 2015 1,500 0.4

Totals 23,500 $8.9

Source: California Energy Resources Scheduling Division of the Department of Water Resources.

* Annual projections may vary due to contract use and other assumptions.

in a financial position to adequately secure electricity and meet the 

needs of their customers. The legislation granted Water Resources 

the authority to purchase electricity, issue bonds to pay for the 

electricity, and provide a mechanism for the State to collect its costs 

from the utilities and, ultimately, their electricity customers. To 

assist in stabilizing electricity prices, and to enhance the reliability 

of the supply, Water Resources entered into a total of 57 long-term 

contracts as of the end of October 2001, at a cost of $42.6 billion.5

As shown in Figure 4 on the following page, the portion of power 

supplied by Water Resources’ long-term contracts has been 

declining, and in 2009 these contracts will provide only 23 percent 

of the electricity needed under the large investor-owned utilities’ 

projections. By 2010 Water Resources’ contracts will cover only 

18 percent of the utilities’ projected demand, and in 2011 they 

will supply only 12 percent, according to Water Resources. The 

final contract is projected to cover less than 1 percent of the large 

investor-owned utilities’ annual electricity needs between 2012 

and 2015.

Currently, the three large investor-owned utilities are responsible 

for managing the balance of their electricity purchases that are not 

covered by the Water Resources’ long-term contracts. Each utility 

must procure electricity to supply the balance remaining based 

on the utility’s energy forecasts. The utilities must submit each 

proposed long-term electricity contract to the CPUC for review. 

As part of its oversight responsibilities, the CPUC determines 

5 We obtained the number of long-term contracts and total cost from the Bureau of State 

Audits’ report, California Energy Markets: The State’s Position Has Improved Due to Efforts by the 

Department of Water Resources and Other Factors, but Cost Issues and Legal Challenges Continue, 

Report 2002-009, April 2003. 
California State Auditor Report 2008-602

June 2009

34

whether the rates under each contract are just and reasonable. As 

shown in Figure 4, the investor-owned utilities currently supply 

approximately 77 percent of the electricity their customers need.

Figure 4

Percentage of Electricity That Has Been or Will Be Supplied to Customers of Large Investor-Owned Utilities by the 

Department of Water Resources’ Long-Term Electricity Contracts

Net electricity supplies secured by 

large investor-owned utilities

Electricity supplied by Department 

of Water Resources’ contracts

2003 2004 2005 2006 2007 2008 2009 2010 2011

Projections*

2012

through

2015

Megawatts (in Thousands)

0

50

100

150

200

250

31% 36% 32% 30% 29% 22% 23% 18% 12% Less than 1%

Source: California Energy Resources Scheduling Division of the Department of Water Resources (Water Resources).

Note: Historical percentages (2003 through 2008) are approximate and are based on a Water Resources’ analysis of publicly available information from 

large investor-owned utilities (Pacific Gas and Electric Company, Southern California Edison, and San Diego Gas & Electric Company).

* Projected percentages are based on Water Resources’ October 29, 2008, final revised revenue requirement filed at the California Public Utilities 

Commission and November 2007 California Energy Commission projections of consumption by customers, also known by the industry as 

load requirements.

Financial Recovery of Large Investor‐Owned Utilities Since the Energy 

Crisis Has Raised Concerns Over Efforts to Eliminate Water Resources’ 

Role in Supplying Power

Although the CPUC believes customers would benefit if Water 

Resources were removed from its role as energy supplier, according 

to credit rating agencies this could have an adverse effect on the 

utilities’ credit ratings, resulting in higher borrowing costs and 

ultimately affecting their overall financial stability. As Water 

Resources’ management pointed out, some contracts specify 

minimum credit ratings the utilities must meet in order to assume 

the contracts, while others lack a clause requiring the seller to 
California State Auditor Report 2008-602 35

June 2009

release Water Resources from its obligations 

under the contract. Thus, there is some uncertainty 

as to whether the utilities will be able to take over 

the existing contracts or negotiate replacement 

contracts that will benefit the ratepayers.

A CPUC ruling dated November 2008 identified 

potential cost savings from reduced administrative 

costs if Water Resources were removed as a 

party to the contracts. Although the CPUC 

acknowledged that the potential savings cannot be 

accurately estimated, it believes that a net savings to 

ratepayers is a reasonable prospect, and the CPUC 

set January 2010 as its goal for eliminating Water 

Resources’ role in supplying power, including its 

role in the remaining contracts. To accomplish 

this, a working group was established to develop 

protocols and strategies for renegotiating or 

replacing the contracts. According to the CPUC’s 

ruling, each utility, along with Water Resources, will be responsible 

for negotiating its assigned replacement agreements; however, the 

CPUC will review and approve the contracts to determine that they 

are just and reasonable. Water Resources agrees that its role as an 

energy supplier should end if ratepayers’ costs will not increase as a 

result, and it is working with the CPUC toward that goal. However, 

Water Resources recognizes that eliminating its contractual 

responsibilities by January 2010 will be a challenge.

Some long-term contracts may be more difficult to transfer to a 

utility or to renegotiate because they do not require the seller to 

release Water Resources from its obligations, and some include 

a requirement that the utility assuming the contract must meet 

minimum credit requirements. According to Water Resources’ 

analysis of the investor-owned utilities’ credit ratings as of 

June 2008, there is uncertainty as to whether the utilities can meet 

the minimum credit ratings required by some long-term contract 

agreements. For example, as we mentioned earlier, PG&E filed 

bankruptcy as a result of the energy crisis, and its credit ratings 

have not yet recovered to the level required in some of Water 

Resources’ long-term contracts. According to a CPUC decision 

dated November 2008, PG&E’s bankruptcy settlement required that 

until PG&E’s credit rating reaches a specified level—which it has 

not yet attained—the CPUC cannot require that it assume any of 

Water Resources’ long-term contracts. The CPUC decision further 

indicates that PG&E can waive this requirement. PG&E has stated 

that it is not willing to do so at this time but would reconsider this 

choice, depending upon the potential benefits it would receive.

Options for Modifying Existing Contracts for 

California’s Electricity Supplies

Novation: Completely removes Water Resources from any 

subsequent financial or operational responsibility for the 

contract. The utility enters into a replacement contract 

with the seller and performs all of Water Resources’ 

former responsibilities.

Assignment: Transfers Water Resources’ contractual 

rights and responsibilities to the utility. Unlike novation, 

assignment leaves Water Resources liable unless there is a 

release of liability by the seller.

Source: Department of Water Resources’ Overview of DWR 

Power Contracts: Background and Review of Portfolio Novation 

and Assignments to the California Investor-Owned Utilities, 

June 2, 2008.
California State Auditor Report 2008-602

June 2009

36

By assuming Water Resources’ long-term contracts, the utilities 

would be increasing their debt, which may negatively affect their 

financial statements. In its June 2008 presentation to CPUC, Water 

Resources estimated that if the utilities assumed the long-term 

contracts on January 1, 2009, they would increase their debt by 

approximately $532 million.

Despite the potential benefits and cost savings that the State 

may realize if the utilities take over Water Resources’ long-term 

contracts, the potential impact on the financial stability of the 

utilities remains uncertain. If the utilities’ credit ratings decline, 

there is some risk that they may be unable to enter into additional 

long-term contracts or make short-term market purchases.

Efforts to Reinstate Direct Access Have Raised Additional Concerns

When it authorized Water Resources to purchase power on 

behalf of the utilities, the Legislature suspended direct access, a 

retail option that enables customers to choose another electricity 

provider. The legislation required that the direct access suspension 

remain in effect until Water Resources is no longer supplying 

power. Suspending direct access, according to a September 2001 

decision by the CPUC, provided a stable customer base from which 

Water Resources could recover the costs of the power it purchased.

In December 2006 a group representing power suppliers and 

various private and public electricity consumers petitioned the 

CPUC, requesting that it lift the suspension on direct access prior 

to the expiration of Water Resources’ contracts and arguing that 

they did not believe the Legislature intended for direct access to be 

suspended for this long. The CPUC concluded that it could not lift 

the suspension on direct access because Water Resources continues 

to supply electricity under its long-term contracts for eventual 

sale to retail customers. However, it decided that there was merit in 

considering ways to expedite the removal of Water Resources as a 

power supplier and, ultimately, to reinstate direct access.

There is some uncertainty as to the impact that restoring direct 

access would have on the large investor-owned utilities. For 

example, in its 2008 annual report, PG&E identified uncertainties 

associated with its ability to recover all its costs if its number of 

customers declines due to the general economic downturn and 

the restoration of direct access. Additionally, a January 2009 

Standard and Poor’s credit analysis indicated that certain policies, 

including the potential for the State to restore direct access, make 

it difficult to determine the utilities’ long-term credit stability. 

More specifically, with respect to Southern California Edison, the 

credit analysis went on to explain that direct access complicates 

After power suppliers and various 

private and public electricity 

consumers petitioned the CPUC 

in 2006, it decided that there 

was merit in considering ways to 

expedite the removal of Water 

Resources as a power supplier and, 

ultimately to reinstate direct access.
California State Auditor Report 2008-602 37

June 2009

the utility’s electricity procurement process, which could result in 

an inability for the utility to recover all of its costs. Thus, if direct 

access is reinstated without full consideration of the impact on the 

utilities, there is some risk that the utilities’ financial stability could 

again be impaired, reducing their ability to negotiate competitive 

prices and purchase adequate electricity to meet the needs of 

their customers.

Meeting California’s Renewable Resource Targets Will Be Challenging

Since the energy crisis, California has adopted targets to increase 

the use of renewable sources of electricity. However, the State is 

at risk of failing to meet these targets because various obstacles 

are preventing the construction of the infrastructure needed to 

generate and transmit electricity from such renewable sources as 

wind, solar, geothermal, biomass, and small hydroelectric facilities. 

To help increase the total production of renewable electricity 

statewide, the State adopted a renewables portfolio standard. 

Moreover, the Legislature established a target of generating 

20 percent of California’s total retail sales of electricity from 

renewable energy resources by December 31, 2010. According to 

the Energy Commission, in 2007 roughly 12 percent of the State’s 

electricity was supplied by renewable sources. Additionally, the 

governor recently announced a more aggressive target, increasing 

the target to 33 percent by 2020. However, the State needs to 

overcome a number of barriers before it can meet either of 

these targets.

The Energy Commission and the CPUC are responsible for 

implementing the State’s renewables portfolio standard. The 

Energy Commission has sponsored programs to encourage 

the development of renewable electricity production, increase 

consumer education, and subsidize the use of electricity generated 

from renewable sources through rebates. The Energy Commission 

also certifies and tracks facilities whose generation applies toward 

meeting the State’s targets for producing renewable electricity. In 

addition to assessing the investor-owned utilities’ procurement 

plans for meeting these targets, the CPUC determines annual 

procurement targets, reviews all proposed long-term contracts, and 

enforces compliance.

According to the Energy Commission, some of the difficulties 

that the State faces in meeting its renewable energy targets 

include those involving the siting and construction of renewable 

electricity generators, such as wind and solar facilities. For example, 

according to the federal Bureau of Land Management (BLM), 

large solar thermal power plants require many acres of land to 

gather sufficient radiant energy. The BLM anticipates that new 

Some of the difficulties the State 

faces in meeting its renewable 

energy targets include siting and 

constructing renewable electricity 

generators, such as wind and 

solar facilities.
California State Auditor Report 2008-602

June 2009

38

solar power plants may require an average of at least 500 acres to 

produce 100 megawatts of electricity. Additionally, the amount of 

sunlight reaching the earth’s surface is affected by the season, time 

of day, climate, and air pollution. Information from the National 

Renewable Energy Laboratory, which is part of the U.S. Department 

of Energy, indicates that the Mojave Desert’s potential for the 

siting of solar power plants is as great as or greater than that of 

any other region in the country. However, according to Energy 

Commission documents, the transmission infrastructure serving 

the area requires expansion. According to the CPUC, it has 

approved several new transmission lines to facilitate the delivery of 

renewable energy to consumers, and others have been proposed.

Associated with the issue of constructing renewable energy 

generation facilities in remote areas, as the Energy Commission 

points out, is the complex regulation of the construction 

of new transmission lines. In particular, the agencies that 

provide regulatory approval and oversight for constructing the 

lines can vary depending on where the lines are located. For 

example, different federal agencies have permitting oversight 

for long-distance transmission lines depending on what federal 

land the proposed facilities will be built. Additionally, the ISO must 

approve the interconnection of any new power-generating facilities 

to the electric grid within its control area. Each of these entities may 

apply different criteria to the process before granting their approval.

Several other barriers exist that could affect the development of 

renewable energy sources. For example, according to the Energy 

Commission, the demand for electricity can vary throughout the 

day as well as by season. To some extent, these variations determine 

the type of renewable energy sources that are most feasible. For 

instance, according to information from the Energy Commission, 

wind generation can peak at various times of the day or night, 

depending on the season and location. These peak times may not 

coincide with peak demand, which occurs in midafternoon to early 

evening. Solar power offers an attractive approach to help meet the 

demand for electricity, because its period of greatest availability 

roughly coincides with the timing of California’s peak demand. 

However, according to the Energy Commission, to help ensure that 

the electric grid does not fail, local reliability requirements often 

necessitate that electricity be generated close to demand areas. As 

we just discussed, however, many of the renewable energy sources 

would likely be constructed in remote locations. Additionally, the 

process for approving new generation can take more than a year 

and, according to the Energy Commission, an influx of new and 

less-experienced developers who may not understand the complex 

project development process might contribute to the difficulty in 

The difficulty in licensing new 

generation facilities could be 

due to the lengthy process for 

approving new generation and an 

influx of new and less‐experienced 

developers that may not 

understand the complex project 

development process.
California State Auditor Report 2008-602 39

June 2009

licensing new generation facilities. As a result of these and other 

factors, siting and constructing renewable generation can be a 

difficult process.

All of these barriers play a role in whether and when California 

can meet its renewable energy targets. In the 2008 update to the 

Energy Action Plan, the Energy Commission and the CPUC point 

out that the State will likely not achieve the target of generating 

20 percent of California’s total retail sales of electricity from 

renewable energy resources by 2010. However, state agencies that 

are responsible for regulating California’s energy infrastructure have 

begun taking steps toward overcoming these barriers. For instance, 

in November 2008 the governor signed an executive order that 

established a Renewable Energy Action Team to create a one-stop 

process for permitting renewable energy facilities. Another example 

of action by state agencies is the Renewable Energy Transmission 

Initiative (RETI), a statewide initiative to facilitate and coordinate 

the planning and permitting of transmission and generation 

projects needed to make progress toward the State’s renewable 

policy targets. According to the Energy Commission’s Web site, 

the Energy Commission, the CPUC, the ISO, and three publicly 

owned utilities are coordinating the RETI effort. Additionally, the 

ISO has created an Integration of Renewable Resources Program 

to foster the integration of renewable resources into the electric 

grid. Finally, the federal American Recovery and Reinvestment 

Act of 2009 (Recovery Act) allocated $275.6 million to the Energy 

Commission for programs related to energy efficiency and 

renewable energy. According to the Energy Commission’s Web site, 

these funds will be administered under two programs: the State 

Energy Program (Energy Program) and the Energy Efficiency and 

Conservation Block Grant Program. The Energy Program provides 

funding for retrofits of buildings and industrial facilities to make 

them more energy efficient and supports renewable energy projects 

and other activities. The energy block grants assist local and state 

governments in implementing projects and programs that reduce 

total energy use and fossil fuel emissions, among other efforts. 

Additionally, the U.S. Department of Energy will provide up to 

$36 billion nationwide through competitive grants funded under 

the Recovery Act for climate change and energy-related programs. 

In total, California is expected to receive an estimated $1.3 billion in 

Recovery Act funds for energy-related purposes.

It Is Too Early to Tell Whether the ISO’s New Market Structure Will 

Continue to Succeed

On March 31, 2009, the ISO went live with its Market Redesign and 

Technology Update (MRTU). MRTU is a project that reintroduces 

day-ahead electricity trading and establishes a new wholesale 

According to two electricity 

regulators, the State will likely not 

achieve the target of generating 

20 percent of total retail sales of 

electricity from renewable resources 

by 2010.
California State Auditor Report 2008-602

June 2009

40

pricing scheme and a new computer model of the electric grid. The 

ISO expects MRTU to result in more reliable delivery of electricity, 

greater wholesale price transparency, and an increase in investment 

in electricity infrastructure.

In December 2001 FERC ordered the ISO to design a new 

day-ahead market, with the goals of reducing the volatility of 

wholesale electricity prices and relieving electricity scheduling 

problems. Many market participants expressed concerns with 

the endeavor—in fact, because of the multitude of stakeholders 

involved and the complexity of the system, it took the ISO more 

than seven years to work out the details of the market redesign and 

gain final FERC approval to introduce the changes. In the interim, 

utilities procured electricity through long-term contracts and in 

the ISO’s real-time market. Because MRTU has been in operation 

only since March 31, 2009, its success is still too early to gauge, and 

is another reason we consider electricity to be a high-risk issue for 

the State.

Before the introduction of MRTU, the transmission grid managed 

by the ISO was divided into three zones, generally representing 

Northern California, Central California, and Southern California. 

One price for wholesale electricity was set throughout each zone 

for all wholesale buyers and sellers. These prices did not accurately 

reflect the true cost of generating and transmitting electricity to all 

areas within a zone. For example, the potential high costs of serving 

high-demand areas with insufficient transmission infrastructure 

were borne by all wholesale buyers in a zone. Additionally, before 

the introduction of MRTU, the ISO was able to identify bottlenecks 

between zones only in its day-ahead scheduling. As a result, 

transmission paths inside the three zones that were overloaded or 

insufficient for meeting demand were not identified until real time, 

resulting in increased costs to rearrange schedules in real time and 

creating the potential for service interruptions. According to the 

ISO, in 2004 the cost of managing congestion from bottlenecks was 

$1 billion.

MRTU, according to the ISO, will provide it with the tools to 

remedy market design flaws and inadequacies, as well as provide 

needed software and computer upgrades. MRTU comprises 

three major elements: the Integrated Forward Market (forward 

market), Locational Marginal Pricing (locational pricing), and the 

Full Network Model (network model). The ISO anticipates that 

MRTU will produce greater efficiencies and assurances of electric 

grid reliability, as well as greater wholesale price transparency 

that can help investors estimate potential revenue and build 

profitable transmission lines and power plants. Moreover, because 

the CPUC generally requires that large investor-owned utilities 

It took the ISO more than seven years 

to work out the details of the new 

day-ahead market redesign and gain 

approval to introduce the changes.
California State Auditor Report 2008-602 41

June 2009

contract for 95 percent of their electricity requirements outside the 

short-term markets, typically no more than 5 percent of electricity 

needs will be procured through the ISO’s markets.

In the new day-ahead market, the ISO anticipates an increase in 

competition among the wholesale sellers and a reduction in costs 

that will allow the ISO to better manage congestion along key 

transmission paths where demand may exceed capacity. As we 

discussed in the Introduction, the ISO will also procure its ancillary 

services, which correct supply and demand imbalances and are 

necessary to ensure the reliability and integrity of the electric grid, 

in the day-ahead market. Because transmission capacity, electricity 

supplies, and reserves can be procured simultaneously in the 

day-ahead market, the ISO also anticipates fewer ways for market 

participants to manipulate the market, as was possible in the 

sequential procurement that occurred in the pre-MRTU market.

With locational pricing, the wholesale electricity market under 

the control of the ISO is structured around a system of roughly 

3,000 nodes, instead of the three large zones that were used 

previously. Nodes are part of the MRTU system model that 

represent local generation and transmission costs. The purpose of 

locational pricing is to more accurately reflect the cost of supplying 

specific areas with electricity. According to the ISO, locational 

pricing is already used by independent system operators throughout 

the central and eastern United States, including the New York, 

New England, Midwest, and PJM independent system operators. 

The node prices take into account the cost of generating electricity 

as well as transmission costs, so areas with congested transmission 

lines will have higher wholesale prices than areas with little demand 

or surplus transmission capacity. Although wholesale prices for 

sellers will vary among the 3,000 nodes, the ISO anticipates that 

retail customers will not experience the periodic spikes in the 

short-term markets’ prices, in part because retail prices will be 

averaged over large geographical areas served by individual utilities, 

thereby smoothing any high locational wholesale prices. Also, as 

we mentioned earlier, purchases from the ISO markets typically 

represent only a small fraction of wholesale electricity procurement.

According to the ISO, locational pricing is also expected to assist 

in the development of new transmission and electricity generation 

infrastructure by revealing the true costs of supplying specific areas 

with electricity. For example, locational prices reveal how new 

power plants will affect the grid, helping investors estimate the 

revenue streams they can expect by siting at potential locations. In 

addition, differences in prices among nodes caused by congestion 

will more easily identify areas with congested transmission lines so 

that profit-minded companies and regulated utilities can build new 

lines to improve efficiency and reliability.

Because transmission capacity, 

electricity supplies, and reserves 

can be procured simultaneously 

in the day-ahead market, the ISO 

anticipates there will be fewer 

ways for market participants to 

manipulate the market.
California State Auditor Report 2008-602

June 2009

42

The final element of MRTU is the network model, which is a 

computer model of the entire electric grid operated by the ISO. 

According to the ISO, the new network model should allow it 

to identify any bottlenecks that could result in transmission 

congestion on the network. The ISO can then act to mitigate those 

bottlenecks before and during real-time balancing of the system, 

using ancillary services, thus avoiding excessive costs and increasing 

reliability. With an accurate and complete model of the grid, the 

network model will provide information that will assist the ISO in 

routing electricity.

The ISO recognizes that while it believes the market design has 

been improved, like any market design, it may be vulnerable 

to manipulation by market participants. Therefore, the ISO 

has included programs that will monitor its markets to ensure 

that electricity prices remain reasonable and to keep wholesale 

buyers and sellers from unduly influencing the price of electricity. 

One mechanism checks for transmission constraints by comparing 

scheduled electricity bids against the ISO’s demand forecasts. 

Additionally, the ISO monitors the grid to ensure that areas with 

traditionally high demand have enough electricity supply planned 

to meet the ISO’s demand forecasts.

Although the ISO is confident that the transition to MRTU 

has been successful, market participants recently voiced their 

concerns about MRTU. Specifically, in January 2009, market 

participants filed comments and protests with FERC over the 

implementation of MRTU. These entities included the CPUC; 

the U.S. Department of Energy; various electricity generators; the 

cities of Anaheim, Pasadena, Riverside, and Santa Clara; PG&E; 

Southern California Edison; San Diego Gas & Electric Company; 

Sacramento Municipal Utility District; and the Western Area 

Power Administration. Some market participants gave conditional 

support for the March 31, 2009, implementation date, while others, 

including the U.S. Department of Energy, requested postponement 

of the launch until the ISO addressed their concerns, which 

ranged from the readiness of MRTU elements for implementation 

to concerns about how MRTU will affect pricing. Nonetheless, 

while recognizing that some milestones were yet to be reached, 

the ISO maintained that MRTU was on track for a successful 

implementation on March 31, 2009. FERC accepted the ISO’s 

readiness certification for MRTU on March 13, 2009. Additionally, 

during the ISO’s March 2009 board of governors meeting, the 

three large investor-owned utilities expressed their support for 

MRTU’s start date. MRTU is currently operating in California, and 

as of May 18, 2009, based on seven weeks of experience, the ISO 

stated, “New ISO markets are generally performing well.” However, 

Many market participants initially 

voiced concerns regarding the 

implementation of the Market 

Redesign and Technology Update.
California State Auditor Report 2008-602 43

June 2009

we believe it is still too early to determine whether MRTU will 

continue to be successful and whether the market participants’ 

earlier concerns have been fully resolved.

Several Entities Have Identified a Need to Reorganize the State’s 

Energy-Related Entities

The governor, members of the Legislature, and two independent 

entities within California have called for a reorganization of the 

State’s numerous energy-related entities. Advocates of energy 

reorganization generally believe it would improve efficiency in the 

formulation of a more strategic energy policy and provide for better 

administration of certain energy programs. Because the governor, 

members of the Legislature, and two independent entities have 

identified a need for reorganization, we considered these concerns 

when deciding to designate electricity as a high-risk area.

The governor and certain legislators have tried more than once 

to reorganize and consolidate some of the State’s numerous 

energy-related entities and create a single Department of Energy. 

For example, in 2005 the governor submitted to the Legislature a 

plan, known as the governor’s reorganization plan, to reorganize 

the State’s energy-related activities by creating a new Department of 

Energy. In the plan, the governor emphasized that California needs 

a more comprehensive approach to energy policy development 

to reduce the level of regulatory uncertainty in the marketplace 

and attract the necessary investment in new resources and energy 

infrastructure to meet future demand. However, the Legislature 

exercised its authority to reject the governor’s proposal. In 

February 2009, Assembly Bill 1016 (AB 1016) was introduced and 

is currently moving through the legislative process. If adopted 

as introduced, AB 1016 would reorganize certain energy-related 

programs in a fashion substantially similar to the governor’s earlier 

proposed reorganization plan.

Also acknowledging the need for California to consolidate energy 

regulatory and policy functions within one department are 

two independent government oversight agencies. For instance, in 

its review of the governor’s 2005 reorganization plan, the Little 

Hoover Commission stated that a compelling case can be made 

that diffused regulatory authority contributed to the State’s clumsy 

response to the energy crisis, and that a more centralized structure 

is needed to forge and execute a cohesive strategy for ensuring 

an adequate supply of energy. The Little Hoover Commission 

stated that organizational changes were necessary and that it 

enthusiastically supported the proposal to create a Department of 

Energy led by a secretary of energy. It also stressed that the need for 

leadership on energy was essential and could not be ignored.

The governor and certain legislators 

have tried more than once to 

reorganize and consolidate 

some of the State’s numerous 

energy‐related entities.
California State Auditor Report 2008-602

June 2009

44

Similarly, in its analysis of the 2006–07 Budget Bill, the Legislative 

Analyst’s Office (legislative analyst) pointed out several problems 

with the organizational structure of the State’s energy entities. 

For instance, it explained that the current structure of California’s 

energy entities reduces accountability by spreading responsibility 

for policy making and regulatory decision making across multiple 

entities. Further, the legislative analyst recommended that the 

Legislature adopt the organizational structure of a consolidated 

department approach, stating that a more accountable and efficient 

organizational structure should improve the State’s ability to 

address its considerable energy challenges in a comprehensive 

manner while allowing enough flexibility to adapt to new challenges 

as they arise. Finally, because any reorganization presents inherent 

risks that require mitigation, the legislative analyst identified 

general risks related to government restructuring, including that it 

is a time-consuming, tedious process that takes a lot of effort and 

commitment with no guarantee of success.

The Bureau Will Continue to Monitor Developments in the Electricity 

Sector and in Related Policies and Programs

Our assessment of current electricity issues has led the bureau 

to add the area of electricity production and delivery to its 

list of high-risk issues. The importance and pervasiveness of 

electricity to our economy and daily lives establishes the need 

for a reasonably priced and reliable supply of electricity. In the 

past, California sought to increase competition in the electricity 

industry; however, the State’s experience with the energy crisis 

of 2000 and 2001 proved that restructuring an industry upon 

which so many citizens rely needs to be based on a well-planned 

strategy and coordination. Because electricity generation, 

transmission, and pricing are statewide issues, the bureau will 

continue to monitor new developments in the industry and in the 

State’s energy policies, identifying any challenges and evaluating 

their effects on the industry’s ability to provide consumers with 

reliable and affordable electricity. To the extent that resources 

are available, the bureau may undertake future projects that 

could include recommendations to improve electricity-related 

policies and programs and to implement those improvements. For 

example, the bureau may monitor developments in the court cases 

affecting the Water Control Board’s proposed policy to eliminate 

the use of the once-through cooling process and the various energy 

agencies’ plans to assure the replacement of electricity supplies. 

The bureau may also report on the status of the efforts to have the 

investor-owned utilities assume Water Resources’ long-term energy 

contracts and on the success of efforts to reinstate direct access as a 

competitive retail option. Also, should major developments occur, 

Two oversight entities have 

expressed concerns with the 

organizational structure of 

the State’s energy entities and have 

proposed creating a consolidated 

Department of Energy.
California State Auditor Report 2008-602 45

June 2009

the bureau may consider deeper evaluations of MRTU, the State’s 

ability to meet its renewable resource targets, and, if one is created, 

the effectiveness of a new state Department of Energy.

We prepared this report under the authority vested in the California State Auditor by Section 8546.5 of 

the California Government Code.

Respectfully submitted,

ELAINE M. HOWLE, CPA 

State Auditor

Date: June 16, 2009

Staff: Denise L. Vose, CPA, Audit Principal 

Melissa Arzaga Roye, MPP 

Christopher P. Bellows 

Kim L. Buchanan, MBA 

Sean R. Gill, MPP

Legal Counsel: Janis Burnett

For questions regarding the contents of this report, please contact 

Margarita Fernández, Chief of Public Affairs, at 916.445.0255.
California State Auditor Report 2008-602

June 2009

46

cc: Members of the Legislature

Office of the Lieutenant Governor

Milton Marks Commission on California State 

Government Organization and Economy

Department of Finance

Attorney General

State Controller

State Treasurer

Legislative Analyst

Senate Office of Research

California Research Bureau

Capitol Press