CSA
Summary
Read the report at California State Auditor ↗
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
April 2003
2002-009
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April 2, 2003 2002-009
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 required by Assembly Bill 1 of the 2001-02 First Extraordinary Session, the Bureau of State Audits presents
its second audit report concerning the Department of Water Resources’ (department) management of the power-
purchasing program.
This report concludes that in the aftermath of the California energy crisis of 2000 and 2001, the department has
had some successes in renegotiating its power contracts to better match consumer demand, reduce contract costs,
and improve the terms of the agreements. During 2002, the department was able to minimize its sales of surplus
power, but it was not able to coordinate the dispatch of its power resources with those of the investor-owned
utilities, an action that could have produced savings to ratepayers.
Even though the investor-owned utilities are again responsible for providing power to cover the net short, including
dispatching the power from the department’s contracts, the department faces continuing challenges in managing the
financial and legal risks in its contract portfolio. These challenges include the department’s ongoing stewardship
of the Electric Power Fund, mitigation of the potential high costs of its contracts, management of its operating and
service agreements with the utilities, and the administration of the bonds issued to finance the power-purchasing
program. Further, many aspects of the State’s power market remain unresolved including creditworthiness of the
utilities, long-term governance of the utilities’ power procurement practices, further development of new power
supplies, and dealing with the outcomes of outstanding investigations and litigation associated with the power
crisis.
Respectfully submitted,
ELAINE M. HOWLE
State Auditor
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CONTENTS
Summary 1
Introduction 9
Chapter 1
With Renegotiated Contracts and a Reduction in
Forecasted Demand, the Contracted Electricity
Portfolio Better Matches California’s Needs and
Better Tracks Changes in Fuel Costs 21
Chapter 2
While the Renegotiation Effort Will Provide Some
Savings to Ratepayers, the Department’s Portfolio
Still Remains Above Market Prices 45
Chapter 3
The Renegotiated Contracts Improve the Reliability
and Flexibility of the Department’s Energy Portfolio,
but Challenges Remain 67
Chapter 4
Sales of Surplus Power Have Not Significantly
Affected the Costs of the Power-Purchasing
Program 91
Chapter 5
The Department Was Not Able to Achieve
Coordinated Dispatch of Power Supplies
That Could Reduce Costs 107
Chapter 6
The Department Will Continue to Face Cost and
Legal Challenges 113
Recommendations 134
Appendix A
A Summary of the Department’s Progress
Toward Implementing the December 2001
Recommendations of the Bureau of State Audits 137
Appendix B
Detailed Tables to Support Summary Data Shown
in Chapter 1 143
Appendix C
Detailed Report Card of Terms Revised Through
Renegotiations for Those Contracts Reviewed in
Our December 2001 Audit 147
Responses to the Audit
Resources Agency 151
Department of Water Resources 152
California State Auditor Report 2002-009 11
SUMMARY
RESULTS IN BRIEF
Forced to act quickly to restore stability to the State’s
electrical power system during the California energy crisis
of 2000 and 2001, the Department of Water Resources
Audit Highlights . . . (department) entered into a number of long-term contracts
for electricity, many of which later proved to be unfavorable
The Department of Water
to the State. This report follows up on a previous audit report
Resources (department)
issued in December 2001 that examined those contracts and the
has renegotiated 23 power
contracts with 14 suppliers to department’s power-purchasing role and called for a strategic
improve the energy delivery, framework for California’s electricity industry. The department
financial, and legal aspects of
has had some success in renegotiating the contracts to fit the
these contracts. In addition,
power supply more closely to consumer demand and to improve
the investor-owned utilities
are once again responsible for the terms and conditions of some contracts. In addition, the
purchasing the net short. responsibility for purchasing the net short (any electricity that
the utilities themselves cannot supply) has reverted back to the
• The portfolio better
fits California’s power three largest investor-owned utilities (Pacific Gas & Electric,
needs by converting Southern California Edison, and San Diego Gas & Electric).
nondispatchable power to
However, significant future challenges in energy issues remain
dispatchable power, but
much of the improved fit for the department, the California Public Utilities Commission,
is due to a reduction of and the investor-owned utilities, particularly with respect to
forecasted demand, not
management of the contract portfolio.
the renegotiated contracts.
• Reported contract cost During the height of the energy crisis, extreme shortages of
reductions were estimated
electricity caused numerous warnings of blackouts and in some
at $5.5 billion on a
cases led to rolling blackouts. At the same time, electricity prices
nominal basis and based
on assumptions at the in the State rose to all-time highs, causing credit problems for
time of the renegotiations. the State’s three largest investor-owned utilities and leading to
a reluctance on the part of generators of electricity to sell power
• The terms and conditions
of the restructured to the utilities. In response to this crisis, the governor declared
contracts have significantly a state of emergency and the Legislature gave the department
improved reliability, but
the authority to purchase the net-short energy required by the
the department remains
three utilities. The department was given this responsibility
restricted in its ability to
assign contracts to other by Assembly Bill 1 of the 2001–02 First Extraordinary Session
parties and thus remains (AB 1X). On January 1, 2003, after nearly two years of
legally and financially
purchasing the net-short energy for the investor-owned utilities,
responsible.
the department’s power-purchasing responsibility ended and
continued on next page the utilities themselves became responsible for purchasing the
energy needed to cover their net-short requirements.
California State Auditor Report 2002-009 11
• Based on March 2003 Our December 2001 report observed that the responsibility
market assumptions, assigned to the department by AB 1X was an immense challenge,
replacement power
given the crisis situation, the short time to prepare for this new
costs, and discounting
to present value, the role, and the department’s limited power-purchasing experience
department consultant and lack of infrastructure relative to the scale of this effort.
currently estimates
Despite these impediments, the department did step in and buy
ratepayer savings
the power needed to keep the lights on in California. In fulfilling
as $580 million.
its new role, the department entered into 52 long-term contracts
• During 2002 the depart-
with a face value (nominal value) of $42.9 billion to deliver
ment was not able to
power in California, and it spent approximately $10.7 billion to
coordinate its power
supplies with the utilities’ purchase power to meet the State’s daily power needs through
generating facilities so as to the first nine months of 2001. However, our report concluded
minimize ratepayers’ costs.
that the department needed to make improvements in several
Even though the investor- areas, including improving the terms and conditions of the
owned utilities have resumed power contracts it had entered into, managing the future cost
purchasing the net short, the
and legal risks of these long-term contracts, and developing
department retains substantial
the infrastructure to support its power-purchasing role. In
responsibilities, including:
addition, in the wake of California’s failed deregulation plan,
• Stewardship of the Electric
we recommended that the governor and Legislature develop a
Power Fund.
strategic framework for California’s electricity industry.
• Vigilance to mitigate the
potential high costs of
Since our December 2001 report, the department has made
its contracts.
progress in implementing our recommendations, but much
• Management of operating remains to be done to manage the continuing financial and
and service agreements
legal risks that face the State. The department has renegotiated
with the investor-owned
the terms and conditions of 23 long-term power contracts with
utilities.
14 suppliers, representing over one-half of the total value of
• Administration of the
the portfolio. These renegotiated contracts contribute to the
bonds issued to finance
improved fit of the portfolio to the State’s forecasted demand
the power-purchasing
program. for power by converting significant amounts of nondispatchable
or must-take power—power that the department was obligated
to purchase regardless of the need—to power deliveries the
department can use when needed. In addition, the renegotiated
portfolio increases power deliveries in Northern California
in 2002 and 2003 to meet demand. Further, the department
was able to shift some deliveries of power from Southern to
Northern California, which reduced the amount of surplus
power projected in Southern California. The department also
renegotiated for more capacity tied to tolling agreements—cost-
management arrangements that allow the department either to
purchase the fuel needed for the power facilities under contract
or to tie the fuel cost to the current cost of natural gas.
However, most of the improvement in the fit of the power
supply to the demand has resulted from significant changes in
the demand forecast rather than from significant improvements
22 California State Auditor Report 2002-009 California State Auditor Report 2002-009 33
in the power contracts. These changes in the forecast include
reductions in the demand for power from the investor-owned
utilities for a variety of reasons, including the ability of certain
electricity customers to buy electricity from alternate suppliers.
The contract renegotiation efforts have reduced the costs of
the department’s contract portfolio. The savings resulting from
the renegotiated contracts can be calculated in a variety of
ways, each with some merits and each with some limitations.
Throughout the energy crisis, the department and the governor’s
office reported both the contract costs and the savings in terms
of the contract payments to suppliers. Thus, they reported that
the estimated reductions in contract costs from the restructuring
of the contracts totaled approximately $5.5 billion, which
represents approximately 13 percent of the total original
contract costs of $42.9 billion. These contract cost reductions
were based on information available at the time of the
renegotiations and were calculated using a negotiation model
that the department used when evaluating the effect of different
renegotiation options on the reduction in contract costs.
While this savings estimate reasonably reflects reductions in
the nominal cost of the contract portfolio to the department,
an alternative analysis would estimate the savings to the
utilities’ customers. With consideration of the replacement
power costs and using a revenue requirement model, a
department consultant currently estimates that the net savings
to ratepayers in nominal terms is $1.5 billion. Also, because
these savings will occur over the next 20 years, the department
consultant currently estimates that the net present value of
the future stream of savings to ratepayers is $580 million.
These March 2003 estimates of customer savings are a function
of economic, market, and dispatch assumptions used by the
department consultant in its modeling and would change if
those assumptions changed. Also, the department indicates that
its revenue requirement model is not designed to value nonprice
benefits resulting from the renegotiation efforts, such as the
improved availability and reliability provisions in the contracts.
Further, most of these contract cost reductions will result
not from reducing the price per megawatt-hour of the power
purchased but rather from shortening the length of the contracts
or reducing the amount of power to be delivered. However,
this reduction of contract length contributed to a department
objective to shorten the time that it would have financial or
legal responsibility for the contracts and, in the process, permit
the utilities to procure energy themselves to meet the additional
uncovered net short.
22 California State Auditor Report 2002-009 California State Auditor Report 2002-009 33
According to the department, the March 2003 estimate of
savings to the consumer from the renegotiated contracts as
of December 31, 2002, using the revenue requirement model,
was made only at our request, and the department would not
otherwise have made this calculation. In addition, the amounts
are from its consultant’s draft report, and as of March 17, 2003,
the amounts had not gone through the department’s ordinary
standards of review for reports of this nature. However, this
is the only estimate the department provided to us of the
savings to the consumer from the renegotiated portfolio as of
December 31, 2002. Further, we observed that these forecasts
are consistent with the forecasts prepared by the department
consultant in establishing the department’s revenue requirements
and were also used in support of the revenue bonds that the
department issued in October and November 2002.
Our review of the legal terms and conditions of the restructured
contracts indicates that although the economic benefits to
individual consumers are likely to be modest, the renegotiations
have generally resulted in improved terms over those in the
original contracts, as shown in our updated report card evaluation
of certain contracts. For example, we found that the restructured
contracts have much stronger guarantees that the sellers will
deliver the power promised under the contracts and build the
new generation facilities promised in the contracts. As a result,
the renegotiated contracts better meet the reliable energy goals
of AB 1X and thus better ensure the availability of electricity to
satisfy consumer demand. These improvements are accomplished
through stronger terms and conditions, such as termination rights
for the State and penalty provisions when sellers fail to deliver
energy or construct new generation facilities as promised under the
contract. Changes in the type of energy products purchased under
the contracts also increase the reliability of the department’s long-
term contract portfolio. Both the stronger terms and conditions,
and the product changes are likely to provide economic benefits
to ratepayers.
Another benefit from the renegotiations is that the State has
entered into settlement agreements with suppliers, in some
cases substantial ones. In most of these settlements, the
suppliers agreed to cooperate with the attorney general’s energy
investigation and to make financial settlements to the State.
While the restructured contracts are better from a legal
standpoint, significant risks remain for the department,
particularly in the contracts that the State has not renegotiated.
44 California State Auditor Report 2002-009 California State Auditor Report 2002-009 55
An area of continuing concern is the restrictions on the
department’s ability to assign the contracts to other parties,
particularly to the investor-owned utilities. Now that the
department’s power-purchasing authority under AB 1X
has expired, the investor-owned utilities have resumed
purchasing the net short and have also assumed the day-to-
day management and operation of the contract portfolio.
Nonetheless, the department remains legally and financially
responsible for the contracts, until either the investor-owned
utilities meet certain credit standards or suppliers decide to
release the department from this obligation. As a result, the
department continues to have significant ongoing legal and
technical responsibilities for the management of the long-
term contracts and could retain those responsibilities for the
remaining life of the contracts.
In our December 2001 audit, we indicated that in future years
the department would have significant amounts of surplus power
that it would need to sell. In 2002 the department did sell surplus
power, but these sales were not significant in proportion to the
department’s total purchases. Our consultant advises us that the
costs reported from the department’s surplus power sales do not
appear unreasonable. Although the department’s renegotiation
efforts have reduced the potential for surplus power sales in future
years, it is still likely that significant sales will occur, particularly
in the years 2003 through 2005. However, because providers of
the net short must ensure that they have sufficient power to meet
demand, some sales of surplus power are inevitable to ensure a
sufficient supply of power.
The department was not able to achieve a coordinated dispatch
of power supplies between the contract portfolio and the
investor-owned utilities’ generating facilities so as to minimize
costs to ratepayers. The electric power that the retail customers
of the investor-owned utilities purchase is obtained from a
variety of sources—hydroelectric dams, nuclear, and fossil fuel-
fired power plants that the utilities own, as well as a variety of
contracts with suppliers entered into by the department and
the investor-owned utilities—each with a different cost per
unit of power delivered during different times of the day and
week. As such, there is an opportunity each day to optimize this
mix of sources to provide power at the lowest possible cost. In
our December 2001 audit, we cite a specific example in which
small savings in daily power costs could result in annualized
savings to the ratepayers of tens of millions of dollars. However,
the department has been unable to implement a coordinated
44 California State Auditor Report 2002-009 California State Auditor Report 2002-009 55
dispatch of power sources with the investor-owned utilities. It
attributes this inability, to some degree, to the investor-owned
utilities’ failure to share with the department information about
the availability of their generating facilities and the terms of
their third-party contracts, as well as to fluctuations in demand
forecasts by the investor-owned utilities that make minimizing
purchase costs more difficult.
Finally, substantial work remains to be done by others to restore
California’s electric markets to full health and to manage
the power portfolio assembled by the department during its
two-year tenure as power buyer for the State. Issues involving
the creditworthiness of the investor-owned utilities must be
resolved, plans must be made for the long-term governance
of the utilities’ power-procurement practices, and changes
are needed in the power market structure to assure that the
markets are effective and well monitored. Although California’s
power supply situation has improved over the past two years,
accounting and credit issues have affected many companies
in the power supply industry, raising questions regarding the
further development of new supplies. Furthermore, substantial
outstanding investigations and litigation associated with the
power crisis are still unresolved. As this range of issues makes clear,
much remains to be done to stabilize the State’s power markets.
In addition to marketwide issues, the department’s ongoing
stewardship of the Electric Power Fund and the contract
portfolio will be an important component of the State’s power
supply for years to come. The contract portfolio is likely to
remain under department management for much of the next
decade and will require continued vigilance to mitigate the
potentially high costs of those contracts. Attendant upon
those responsibilities will be the need for the department to
manage its operating partnerships with the utilities to schedule
and deliver the power and to procure fuel. In addition, the
department will continue to be responsible for managing the
Electric Power Fund and for the administration of the bonds
issued to finance the cost of the AB 1X power program. These
remaining responsibilities carry substantial ongoing obligations
to manage costs and risks and will require a sustained
professional organization at the department to properly protect
the State’s interests.
66 California State Auditor Report 2002-009 California State Auditor Report 2002-009 77
RECOMMENDATIONS
The department’s future activities can be described as falling
into four broad categories, each defined by basic contractual
responsibilities that it will carry into the future. Our
recommendations are that the department continue to (1) meet its
legal and technical responsibilities regarding the contract portfolio,
(2) manage the operating agreements that set forth how the
investor-owned utilities are to operate the contracts, (3) manage the
servicing agreements with the investor-owned utilities under which
the department collects revenues from the utilities to pay for power
and debt service, and (4) service the revenue bonds that were issued
to finance the power-purchasing program.
AGENCY COMMENTS
The department indicates that it appreciates our efforts along
with those of our consultant in preparing this report. n
66 California State Auditor Report 2002-009 California State Auditor Report 2002-009 77
Blank page inserted for reproduction purposes only.
88 California State Auditor Report 2002-009 California State Auditor Report 2002-009 99
INTRODUCTION
BACKGROUND
Under the terms of Assembly Bill 1 of the 2001–02 First
Extraordinary Session (AB 1X), in February 2001 the
Department of Water Resources (department) became
responsible for buying the net-short power needs of the State’s
three largest investor-owned utilities (Pacifi c Gas & Electric
[PG&E], Southern California Edison [SCE], and San Diego Gas
& Electric [SDG&E]) through December 31, 2002. The net short
is the difference between the power that the investor-owned
utilities provide from their own supplies and the total consumer
demand for power at any given time. AB 1X gave the department
its new role in the midst of an unprecedented fi nancial and
reliability crisis in the State’s electricity industry. During the
height of the energy crisis, extreme shortages of electricity caused
utilities to issue numerous warnings and in some
cases led to rolling blackouts. At the same time,
Key Provisions of AB 1X* electricity prices in the State rose to all-time highs,
causing credit problems for the State’s three largest
• The department is authorized to purchase investor-owned utilities and leading to a reluctance
the power necessary to meet the energy
on the part of generators of electricity to sell power
needs of the three largest investor-
owned utilities and to sell the power to to the utilities.
retail customers.
• The department is to build a portfolio of Those primarily affected by the department’s power-
contracts for energy resulting in reliable
purchasing activities are the retail customers of the
service at the lowest possible price per
kilowatt-hour. State’s three largest investor-owned utilities: PG&E,
SCE, and SDG&E. These utilities serve the coastal
• The cost of the power is to be recovered
areas of the State from Eureka to the Mexican
through consumers’ rates.
border and the majority of the State’s inland areas,
• The department’s procurement authority
accounting for approximately 77 percent of the
ends December 31, 2002, but the
department can continue to manage the electrical power consumers in the State.
contracts it enters into.
By January 1, 2003, when the department’s two-
* These provisions became effective on
year power-purchasing responsibility ended, it had
February 1, 2001.
expended approximately $14 billion for power
bought and delivered to consumers. In addition,
the department had assembled a portfolio of
52 long-term power contracts for power to be delivered over
the next 20 years at an estimated cost of $42.9 billion. In buying
that power and executing those contracts, the department
incurred administrative and general expenses of approximately
$79 million during the two-year period.
88 California State Auditor Report 2002-009 California State Auditor Report 2002-009 99
FINDINGS FROM OUR 2001 AUDIT
In compliance with the California Water Code, Section 80270,
in December 2001 the Bureau of State Audits (bureau) released
an audit of the department’s responsibilities under AB 1X,
titled California Energy Markets: Pressures Have Eased, but Cost
Risks Remain. In it, we described the underlying problems
with California’s electricity supply that led to the crisis, the
Legislature’s response to the crisis, and how the mission of AB 1X
dwarfed the department’s capabilities. Our audit concluded
that the department faced an immense challenge in purchasing
the net-short energy of the three investor-owned utilities, but
that it had successfully kept the lights on in California. Further,
we found that although the crisis had eased, the department’s
response to the crisis had created certain financial and legal risks
that would need careful management, as described in Table 1.
TABLE 1
Key Findings From Our December 2001 Audit
• The speed with which the department entered into contracts in response to the
crisis precluded the planning process necessary to implement a power-purchasing
program of this size. As a result, the department assembled a portfolio of power
contracts, which presents significant risks that will need careful management to
avoid increased costs to consumers.
• The portfolio does not contain sufficient power for peak-demand periods, thus
potentially exposing consumers to high-market prices if the energy supply becomes
limited during those periods.
• The majority of the contracts are not written to ensure a reliable source of power
and instead convey lucrative financial terms upon the suppliers to ensure that
energy is delivered. In addition, the contracts contain provisions that can increase
the cost of power; thus, they need careful management to avoid additional costs
to consumers.
• The department lacks the infrastructure needed to properly manage its purchases of
the net short, but is taking steps to build up its capabilities.
• Many decisions need to be made about the State’s future role in the power market.
The department’s authority to contract and purchase the net short ends after 2002,
yet it or another entity will need to manage the considerable market and legal risks
of the power contracts and, if the investor-owned utilities are not creditworthy,
purchase the net short.
• Operational improvements are needed to strengthen the department’s
administration of the power-purchasing program.
We made many recommendations to the department regarding
how to address these findings and how to more effectively plan
and manage the economic and legal aspects of its portfolio.
1100 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1111
In addition, we recommended that the governor and the
Legislature work together to develop a strategic plan for the
future role of the State in the power market. Appendix A
provides a summary of the recommendations from our
December 2001 audit and the actions the department has taken
to implement those recommendations.
RECENT CHANGES THAT HAVE AFFECTED THE
DEPARTMENT’S POWER PROGRAM
Since our December 2001 audit, several changes have occurred
that affect the department’s power program. One of the more
signifi cant of these is the department’s effort to renegotiate
long-term contracts with the intent to obtain more favorable
fi nancial and legal terms and conditions. The renegotiations
were possibly easier to accomplish due to actions fi led by others
against suppliers claiming that they had manipulated the
California energy markets to increase profi ts. In
addition, the department was able to secure the
fi nancing to pay for its power-purchasing activities.
Goals and Objectives of
Finally, the responsibility for purchasing power to
Contract Renegotiation
cover the net short successfully reverted from the
• Reduce nondispatchable energy to shape department back to the investor-owned utilities on
supply to match energy demand.
January 1, 2003.
• Shorten contract terms to avoid purchases
that sellers required but that were not vital
to the State. The State Has Restructured Many of the
Long-Term Power Contracts
• Reduce contract prices to just and
reasonable levels and reduce overall
Recognizing that the fi nancial and legal terms
portfolio costs.
and conditions of the long-term power contracts
• Reduce volumes of purchases in later years
were not favorable to the ratepayers, the State has
of contracts.
worked to renegotiate many of the contracts. The
• Enhance the reliability of energy by
contracts had been criticized by many outside
improving contract terms.
parties as being unfair to the State, and thus in late
• Make contracts assignable to other parties.
2001 the State began making plans to approach
• Facilitate contract administration by improv- sellers to renegotiate the deals. Department
ing the department’s contractual rights. consultants recommended that the contracts be
• Target customer savings of at least 20 percent. renegotiated to achieve certain outcomes and
goals, as shown in the text box at left. Key among
these goals was the need to reduce the amount
Sources: Navigant Consulting, Inc., Renegotiation
of nondispatchable or must-take energy—power
of Power Contracts, October 2002, and Electric
Power Group, Contract Renegotiation Framework and that the department must purchase regardless
Principles, June 2002. Both are consultants for the
of whether it is needed to meet demand—
Department of Water Resources.
because the portfolio that the department had
assembled focused too much on round-the-clock
1100 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1111
nondispatchable energy instead of on energy that could
be dispatched as needed to meet demand at times when
requirements were high. To accomplish the renegotiations,
the State assembled a negotiating team consisting of staff
from several state entities, including the governor’s office, the
California Public Utilities Commission (CPUC), the attorney
general’s office, and the department. Several consultant and legal
firms also assisted in the effort. The governor’s office directed the
renegotiation efforts for most of the contracts.
The first contracts were renegotiated in April 2002, and by
December 2002 the State reported renegotiating or canceling
23 contracts, with a $5.5 billion reduction in contract payments.
In addition, the governor’s office and the department indicated
that the renegotiation effort incorporated many of the
recommendations from our December 2001 audit, including
providing the State with stronger commitments for new power
plants, more flexibility, and greater reliability in obtaining power;
allowing greater freedom to tailor power supply to meet demand;
and improving the department’s ability to assign the contracts to
the investor-owned utilities after they become creditworthy.
In some instances, the renegotiations have included settlements
of claims with the attorney general. For example, two generators
paid $8.5 million to the State in exchange for ending the
attorney general’s claims against them for improper electricity
pricing practices. In addition, the State agreed to discontinue its
action with the Federal Energy Regulatory Commission (FERC)
seeking refunds from the two generators for the allegedly illegal
electricity pricing practices in California. The department reports
that the renegotiation efforts are continuing in 2003.
In Chapters 1 and 2 of this report, we evaluate the economic
benefits and reduction of costs to ratepayers resulting from the
contract renegotiations; in Chapter 3 we discuss the extent to
which the terms and conditions of the contracts have improved.
A Variety of Factors May Have Helped Bring Generators to
the Negotiating Table
As we pointed out in our December 2001 audit, most of the
contracts were lucrative for the sellers, and thus there would
appear to be little incentive for sellers to renegotiate the
contracts. Nonetheless, in early 2002, sellers started coming
to the negotiating table. In doing so, they could have been
influenced by any of several events. As the negotiating team was
1122 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1133
identifying areas in which the contracts could be improved and
opportunities for aggressively managing the contracts, other
state agencies were pursuing relief in other forums from high
prices in contracts negotiated in an electricity market that FERC
has described as dysfunctional. For example, the CPUC and the
California Electricity Oversight Board filed separate complaints
with FERC under Section 206 of the Federal Powers Act. These
complaints made several allegations, chief among them
that the rates under the original contracts are not just and
reasonable or consistent with the public’s interest, as the
Federal Powers Act requires.
In addition, some generators were and are the subject of
numerous civil lawsuits alleging, for example, that they engaged
in illegal practices such as unfair business practices. The attorney
general is investigating whether some generators manipulated
the energy market. Moreover, the California State Senate Select
Committee to Investigate Price Manipulation of the Wholesale
Energy Market continues to investigate the events that led to
the State’s energy crisis, including the possibility of market
manipulation by some of the generators with which the State
has long-term energy contracts, placing additional pressure on
generators. Further, since mid-2001, when the contracts were
signed, various economic factors, including changes in the
energy market, have presented generators with new financial
challenges, which may have provided additional incentive to
renegotiate the contracts. The various pending investigations
and lawsuits have created a climate of uncertainty, which the
sellers could seek relief from, possibly through settlements with
the State. Thus, the State’s willingness to enter into settlement
agreements with sellers that agreed to renegotiate contracts was
likely a factor in getting those sellers to the table and in the
ultimate renegotiation of the contracts.
Delays Have Occurred in Recovering the Billions of Dollars
Lent to the Department to Finance Power Purchases
After a lengthy delay, the department’s mechanism for
recovering the costs of operating the power-purchasing program,
known as the revenue requirement, was formally implemented
in February 2002. The revenue requirement is the amount that
the department determines is sufficient, along with the funds
in the Electric Power Fund, to pay bond costs, to pay for power
purchased, to fund necessary or desirable reserves, to repay
advances from the State’s General Fund for power purchases
with interest, and to pay the department’s administrative costs
1122 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1133
for this program. Under AB 1X, the department is to determine
the revenue requirement at least annually and is to recover it
through the electricity rates that the CPUC establishes.
Before it could be assured that all its costs would be included in
future rates collected by the utilities, the department indicates
that it was advised by its financial advisors and the credit rating
agencies that in order to sell bonds, it was necessary to enter
into a rate agreement with the CPUC regarding the procedures
to follow to determine the charges to ratepayers. The CPUC
delayed approving the rate agreement until February 2002 so
that it could resolve its concerns as to whether the costs and
terms in the long-term power contracts were in the best interest
of the public. It also had some concerns about the lack of
oversight of department costs.
With the approval of the rate agreement and the implementation
of the revenue requirement, the department was able to issue
bonds in October and November 2002 to finance the costs of the
power-purchasing program. These bonds totaled $11.26 billion
plus premium and were used to repay the approximately
$6.1 billion plus interest that had been advanced from
the General Fund and to pay off a short-term loan balance of
$3.5 billion that was issued to help fund power purchases. These
bonds will be repaid from revenues collected from ratepayers
of the three investor-owned utilities, as spelled out in the rate
agreement. The department had originally anticipated issuing
these bonds in mid to late 2001 but had to wait until the rate
agreement was in place.
Responsibility for Purchasing the Net Short Has Reverted to
the Investor-Owned Utilities
On January 1, 2003, the department’s responsibility for purchasing
the net-short energy ended and reverted to the investor-owned
utilities. Although AB 1X provided the department the authority
to procure power only until December 31, 2002, several issues
needed to be resolved before the investor-owned utilities could
resume this role. Key among these issues was the need to provide
assurances to electricity suppliers that the investor-owned
utilities were creditworthy and had the financial resources
to resume purchasing the net-short energy needed by their
customers. By December 2000 both PG&E and SCE had become
uncreditworthy and were financially unable to buy power. PG&E
filed for bankruptcy protection in April 2001. Neither utility had
regained creditworthy status by December 2002. Thus, to enable
1144 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1155
them to resume buying power on January 1, 2003, the California
Independent System Operator (ISO), which operates the State’s
short-term electricity markets, required PG&E and SCE to submit
security deposits to cover their purchasing activities until they
regain full creditworthy status.
Another issue concerned who would manage and dispatch
the energy from the department’s long-term power contracts.
By late December 2002, the CPUC had acted to allocate the
department’s contracts among the investor-owned utilities and
had issued orders necessary for them to fully assume power-
purchasing functions and all the operational, dispatch, and
administrative functions for the allocated contracts, allowing the
utilities to act as agents for the department. This was necessary
because the department’s contracts were written so that the
department could not easily assign its rights and obligations
under the contracts to the investor-owned utilities.
Once the investor-owned utilities began operating the contracts
on behalf of the department, formal operating agreements were
needed to ensure that the department receives the information
it needs to perform its existing statutory and contractual
obligations. Without such agreements, the department would
be vulnerable to financial and legal risks. The operating
agreements, which the CPUC is currently considering for
approval, are intended to mitigate the department’s risks by
providing it assurances on a number of issues, including that
the investor-owned utilities will dispatch energy from their
generating facilities and the department’s contracts in a manner
that results in the least cost to ratepayers. We discuss these
operating agreements in more detail in Chapter 6.
SCOPE AND METHODOLOGY
The California Water Code, Section 80270, requires the bureau to
conduct two financial and performance audits of the department’s
implementation of the power-purchasing program: the first due
by December 31, 2001, and the second due by March 31, 2003.
We completed the first required audit on December 20, 2001, and
this audit fulfills the requirement for the second audit report. To
implement this broad mandate, our first audit focused on the
critical tasks necessary to implement and manage a program to
purchase a sufficient and reliable supply of electric power at the
lowest possible price per kilowatt-hour. In this audit, we follow up
on the department’s actions with respect to the recommendations
1144 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1155
from our 2001 audit. To assist us in forming our conclusions related
to the economic issues involved, we retained the services of an
energy economics firm. This firm, La Capra Associates, performed
various analyses that we requested.
To understand the department’s progress in implementing
the recommendations from our December 2001 audit, we
reviewed its 60-day and six-month responses to the audit. We
also interviewed key department staff, along with staff from the
consulting firms assisting it in performing the duties required
under AB 1X.
A major effort for the department since our last audit—and
one of our key recommendations—was to restructure certain of
the long-term power contracts from the original portfolio that
it assembled in early to mid-2001. Thus, we focused on three
aspects of how the restructuring benefited the department and
ratepayers. Specifically, we looked at whether the restructuring
efforts (1) improved the fit of power deliveries to consumer
demand, (2) resulted in financial savings in terms of contract
cost reductions and reduced costs to ratepayers, and (3) provided
better legal terms and conditions for ensuring that power
suppliers fulfill their contractual obligations. As we noted earlier,
these benefits were among the specific goals and objectives that
the State had set.
To determine whether the restructuring improved the fit of
deliveries to consumer demand, we reviewed department
documents and data to understand the changes to long-
term contracts resulting from contract renegotiation. We
also reviewed the results of the department’s modeling of the
California wholesale power market to obtain information
regarding market prices, along with the generation and power
costs associated with the contract portfolio. We did not review
the terms and conditions of the individual renegotiated
contracts to verify the accuracy of inputs to the department’s
model, but our consultant was satisfied that the department’s
data were reasonably accurate. Our consultant used the model
results to update the capacity, cost, and product-type analysis
of the contract portfolio presented in our December 2001 audit.
Next our consultant compared the contract portfolio before
and after renegotiations to determine whether the renegotiated
portfolio of long-term contracts better met the department’s
future capacity and energy needs and, if so, whether the
improvement was attributable to the renegotiation efforts,
1166 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1177
other factors, or a combination of the two. Finally, we analyzed
whether the cost of electricity supplied by the new portfolio
better tracked changes in gas costs.
In addition, our consultant analyzed the fit of the power
supplies to consumer demand for 2004, using a load duration
analysis. A load duration analysis is a standard tool used
by energy experts to compare on an hourly basis the power
deliveries by product type to forecasted demand. Our consultant
used department data in this analysis to graphically display the
fit of the contract portfolio to forecasted demand before and
after the contract restructuring efforts. Three metrics were used
in our consultant’s analysis: (1) the remaining capacity need
in megawatt-hours, (2) the remaining energy need in gigawatt-
hours, and (3) energy surpluses from must-take contracts. In
each case, the evaluation was conducted for Northern and
Southern California, referred to as north of Path 15 (NP15) and
south of Path 15 (SP15), as well as for the entire area served
by the contract portfolio, for both peak and off-peak periods.
To determine the effect of a change in forecasted demand
on the fit of the contract portfolio to consumer demand, our
consultant also analyzed the fit of the contract portfolio before
renegotiations against forecasts of market conditions as of
mid-2001 and mid-2002.
To determine whether the restructuring efforts resulted in
financial savings, we reviewed the department consultant’s
calculations of contract cost reductions and ratepayer savings.
Our analysis focused on the renegotiated contracts with the
largest reported cost reductions because these contracts represent
approximately 95 percent of the reported cost reductions. For
these contracts, we reviewed the specific terms and conditions
that were renegotiated, to determine whether the department’s
estimates of cost reductions were reasonable. We also sought to
determine the main sources of the cost reductions—reductions
in contract length, quantity of power, or price. In addition, we
reviewed the department consultant’s estimates of ratepayer
savings. We did not conduct a comprehensive review of all the
underlying assumptions used in these calculations; however, our
consultant was satisfied that the calculations were reasonably
prepared. Finally, we compared per-unit costs of energy in the
renegotiated portfolio to the latest forecast of market prices by
the department consultant to assess the degree of improvement
in the renegotiated portfolio relative to current estimates of
competitively priced power.
1166 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1177
To determine whether the restructured contracts provide
better legal terms and conditions for (1) ensuring that power
suppliers fulfill their contractual obligations, (2) providing the
department with more flexibility in managing the contracts,
and (3) facilitating the transfer of the contracts to the investor-
owned utilities, we first compared the terms and conditions of
the renegotiated Calpeak, Calpine, GWF, High Desert, Sunrise,
and Williams contracts, representing approximately 95 percent
of the reported cost reductions, with those of the original
contracts to identify changes in the contracts. We next requested
that the department provide us with a list identifying changes in
the renegotiated contracts based on the criteria we used in the
contract report card presented in our December 2001 report. We
then compared the changes the department identified with the
changes we identified in the renegotiated contracts we reviewed
to determine whether the renegotiated contracts made changes
in areas we identified as weak in the December 2001 report. We
then analyzed each change to determine whether it resulted
in an improvement to the contract. We also reviewed each of
the selected renegotiated contracts for changes to determine
whether the renegotiated contract provides the department with
more flexibility in managing the contract and whether it better
facilitates transfer of the contract to the investor-owned utilities.
Another key recommendation from our previous audit was that
the department carefully monitor levels of surplus energy from
the contract portfolio to ensure that these sales are minimized
so as to avoid increased costs for ratepayers. To analyze the
department’s efforts to control the levels of surplus energy and
the resulting sales, we reviewed reports showing these sales
during 2002. We also obtained information regarding market
prices, the net short, and variations in the net short to better
understand the context within which the sales were made. Using
these data, we identified specific days to analyze to determine
the degree to which sales for 2002 might be explained by sales of
surplus power, changes in the investor-owned utilities’ forecasts
of the net short, and the use of dispatchable contracts to earn
profits to offset the department’s overall energy program costs.
We obtained and reviewed invoices and 10-minute interval data
from the ISO to evaluate the extent to which the department’s
power-scheduling decisions might have been influenced by
the actual, real-time net short. We did not evaluate sales or
imbalance data for every day during 2002. To provide context,
we often have attempted to present our conclusions in
annualized terms. However, in most instances such conclusions
are necessarily extrapolations based on the days in our sample.
1188 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1199
We also analyzed the department’s efforts to minimize the
cost to ratepayers by coordinating the dispatch of power
between the contract portfolio and power sources owned by
or retained by the investor-owned utilities. However, based
on discussions with the department and its consultant, we
determined that no progress had been made toward achieving
a coordinated dispatch of power sources. Thus, we analyzed
documents to develop an estimate of the potential value of a
coordinated hydropower dispatch, representing only one aspect
of a potentially broader coordinated dispatch effort. Because
the department relies upon forecasts of power needs from the
investor-owned utilities to make power-purchasing decisions, we
performed analyses to determine the degree to which changes
in these forecasts of the net short might be complicating the
department’s efforts to minimize the costs of its dispatch. We
did not seek to obtain data from the investor-owned utilities
to estimate the benefit of a fully coordinated dispatch because
these data were unavailable to the department.
The department contracts with a private accounting firm to
audit the Electric Power Fund and its water project funds.
Therefore, we generally limited our financial audit to evaluating
the department’s efforts to segregate properly the expenditures
of the power-purchasing program from the other programs it
administers. We did find several immaterial errors in segregating
expenditures that we brought to the attention of department
management. We also reviewed administrative expenditures
charged to the power-purchasing program and found no
evidence of unauthorized expenditures in the sample we tested.
Because the revenue requirement receives outside scrutiny
from consumer advocates and the CPUC, we did not perform
a detailed review of the department’s methods and analyses in
determining those requirements.
Because of past problems with ensuring that individuals working
in the power-purchasing program disclose potential conflicts
of interest, we reviewed the department’s current practice of
monitoring for such conflicts. We found a few instances of
contractor employees not being screened to determine if they
needed to complete required disclosure forms, which we brought
to the attention of department management.
Finally, we identified and explored the major continuing challenges
with respect to the energy issues facing the department and
the State. We examined provisions in statute, CPUC rulings,
1188 California State Auditor Report 2002-009 California State Auditor Report 2002-009 1199
and formal operating agreements between the department and
the investor-owned utilities, focusing on optimization of the
combined supply portfolios of the department and the investor-
owned utilities to benefit ratepayers. We also obtained the views of
senior staff from the department and its consultants on important
issues confronting the department and the department’s plans for
addressing them. Finally, we reviewed state and federal regulatory
challenges affecting the contract portfolio. n
2200 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2211
CHAPTER 1
With Renegotiated Contracts and a
Reduction in Forecasted Demand, the
Contracted Electricity Portfolio Better
Matches California’s Needs and Better
Tracks Changes in Fuel Costs
CHAPTER SUMMARY
Our December 2001 audit concluded that the contract
portfolio assembled by the Department of Water
Resources (department) contained significant cost risks
that the department would need to manage carefully. Over the
past year, a state negotiating team has reached agreement on
new terms and conditions for 23 of the long-term contracts,
improving the fit of the department’s power supplies to
California’s energy and capacity needs. While the improved
fit has reduced the department’s exposure to cost risk, an
even greater reduction in cost risk results from the forecasted
reduction in the demand for power that the utilities must buy
(the net short).
The renegotiated portfolio better matches California’s power
needs in several critical areas. The portfolio now contains
significantly less nondispatchable or must-take energy—
energy that must be purchased regardless of the need. The
nondispatchable capacity has been replaced in large part by
dispatchable contracts that allow the department to take delivery
only when the power is needed. These changes will allow the
department to significantly reduce its excess energy purchases,
particularly in Southern California, where the capacity under
contract from the fourth quarter of 2003 through the first quarter
of 2005 was expected to exceed average peak demands, resulting
in significant energy surpluses. The total capacity of the portfolio
has also increased in some years, a change that increases the
proportion of the net-short peak demand that is met by long-term
contracts. This, in turn, reduces some of the ratepayers’ exposure
to spikes in spot market prices.
Further, contract renegotiation has increased the amount of
capacity in the portfolio associated with tolling contracts,
in which either the buyer supplies the fuel used to generate
2200 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2211
electricity or the cost of power is tied to the cost of natural gas.
The percentage of capacity that involves tolling has increased by
more than 2,000 megawatts per year above that in the original
portfolio from 2003 to 2010. While this change has increased
the opportunity for California consumers to benefit from lower
natural gas prices in the future, it has also made consumers
more susceptible to the risk of higher gas prices. During 2002
the department did reasonably well in purchasing natural gas
at market prices for its tolling contracts, but in the role defined
by the California Public Utilities Commission (CPUC), it faces
the challenge of ensuring that the investor-owned utilities
appropriately manage future gas purchases.
THE DEPARTMENT SOUGHT THROUGH CONTRACT
RENEGOTIATION TO ALLEVIATE THE COST RISKS
EXISTING IN THE ORIGINAL PORTFOLIO OF CONTRACTS
The department’s renegotiation efforts sought to address
many of the cost risks existing in the contract portfolio
The department assem- that it created during the energy crisis. As we noted in our
bled the portfolio December 2001 audit, the department assembled the portfolio
under extraordinary under extraordinary circumstances and in a short time period—
circumstances, entering 40 agreements with a value of $35.9 billion were entered into
into 40 agreements with in 30 days—which undoubtedly complicated these efforts. Our
a value of $35.9 billion December 2001 audit discussed the advantages and disadvantages
in 30 days. of the department’s procurement strategy and that the original
contract portfolio presented the following cost risks:
• The original portfolio is priced substantially above the future
market prices then projected for power purchased in the
spot market. Forecasts of market prices can be expected to
change over time, affecting the relative cost of these fixed-
price nondispatchable energy purchases. Further, because
these nondispatchable products provide a shelter against the
volatility of spot market prices by locking in a fixed price
for future purchases, it can be expected that such purchases
will, over time, command a premium over market prices,
depending on supply and demand conditions. However,
our consultant believes that the premium paid in the
department’s contracts is greater than what these factors
would suggest it should be.
• The original portfolio provides most of the net-short energy
needed during most hours of the year but much less of the
capacity needed during peak-demand periods. As a result, the
2222 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2233
portfolio would not cover a substantial portion of the peak
demand on hot summer days, when spot market prices are
likely to be at their highest.
• Most of the department’s original contracts are nondispatchable,
meaning that the department must take, and pay for, the power
that it has contracted for. Thus, the original portfolio provides
little flexibility to reduce purchases at times when lower-priced
market power is available or when power supplies exceed
demand. After the crisis eased, a great deal of lower-cost power
did become available, but the department was unable to benefit
significantly from these reduced prices.
• The original portfolio contains relatively few contracts that
allow power prices to float with changes in the price of natural
gas, which was projected to fall from the record high levels that
existed at the time the department signed most of the contracts.
• The original portfolio provides for the delivery of more power
than customers in Southern California are expected to use
during the period from late 2003 through early 2005, creating
the potential for substantial sales of surplus power—likely at a
loss—during that period.
• Despite the legislative intent for the department to procure
as much power as possible from renewable energy sources—
generating sources that produce less pollution than other
sources of energy—less than 2 percent of the power in the
original portfolio comes from renewable sources.
A state negotiating team began an effort to renegotiate selected
long-term contracts in late 2001, with the intent of mitigating
these problems. Through December 2002, the state team had
Through December 2002, renegotiated the terms and conditions of 23 long-term contracts
23 long-term contracts with 14 suppliers. These 23 contracts account for approximately
with 14 suppliers were half of the original portfolio cost of $42.9 billion1, and they
renegotiated, accounting represent 44 percent of the total capacity originally slated for
for approximately half delivery in 2003. This chapter addresses the extent to which
of the original portfolio the renegotiations improved the fit of the original portfolio to
value of $42.9 billion. the State’s future power needs. That is, it addresses whether the
renegotiated portfolio is better able to meet the utilities’ future
net-short capacity and energy requirements at a lower cost and
with reduced energy surpluses.
1In our December 2001 audit, our consultant estimated the cost of portfolio in its first
10 years to be $42.6 billion. The estimate above, $42.9 billion, based on an analysis
performed by the department consultant, incorporates the full life of the portfolio of 20
years using 2001 market assumptions. Some assumptions, particularly fuel prices, may
also differ.
2222 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2233
THE DEPARTMENT WAS ABLE TO REDUCE THE
AMOUNT OF NONDISPATCHABLE ENERGY IN THE
PORTFOLIO AND REPLACE IT WITH DISPATCHABLE
CAPACITY, BUT ROOM FOR IMPROVEMENT EXISTS
Our December 2001 audit noted that most of the contracts
in the department’s portfolio required sellers to deliver, and
the department to take, energy at a constant rate during
specifi ed time periods. For example, most base products in the
department’s portfolio obligated sellers to deliver fi rm energy
at a constant rate 24 hours a day, seven days a week, 52 weeks
a year (known as 7x24 nondispatchable energy products).
Similarly, most peak products committed suppliers to deliver
fi rm energy at a constant rate during peak hours for a specifi ed
number of days per week (such as the 6x16 product, which
delivers energy 16 hours a day, six days a week, 52 weeks a year).
These types of products are known as nondispatchable because
the buyer has no ability to change the rate at which electricity
is taken in order to better match supply and demand or to take
advantage of lower-cost supply alternatives.
For the period from 2002 to 2010, 71 percent of the megawatts
under contract in the original power portfolio were contained
in nondispatchable contracts that provide no fl exibility to
curtail deliveries. Given the variability of electricity supply and
demand, no sizable utility system can perfectly match supply
to demand on an hour-by-hour basis. However, we concluded
that the original portfolio contained too much
nondispatchable power and that the magnitude
of the difference between the department’s
Energy Versus Capacity
nondispatchable energy purchases and the
Energy is a measure of the quantity of net-short energy requirements during certain
electricity produced or delivered over a period
periods of low demand would require the sale of
of time, and is often measured in kilowatt-
hours, megawatt-hours, or gigawatt-hours signifi cant quantities of surplus energy at prices
(where one gigawatt-hour is equal to one well below the full contract cost. We also noted
thousand megawatt-hours or one million
in our December 2001 audit that the quantity of
kilowatt-hours).
surplus energy could increase substantially because
Capacity is a measure of the rate at which
the department’s net-short position is subject to
electric energy can be produced or delivered
at any point in time, and is often measured in signifi cant volatility.
kilowatts or megawatts (where one megawatt
is equal to one thousand kilowatts).
In order to mitigate these portfolio problems,
the department sought to negotiate changes in
its long-term contracts that would reduce the
proportion of nondispatchable capacity in the portfolio and
increase the proportion of dispatchable capacity. Purchasing
dispatchable capacity allows the department to improve the
fi t of its power supplies to the actual demand. In contrast to
2244 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2255
nondispatchable contracts, dispatchable contracts provide the
department the choice to dispatch—or use—the power under
contract when needed, within specified limitations. If demand
falls below supply, the department is not obligated to use or
pay for the power. Dispatchable contracts also provide the
department the option of purchasing the energy on the spot
market, rather than dispatching it from some of its contracts, if
the spot market price is less than the contract price.
Table 2 shows that the department was indeed able to reduce the
amount of nondispatchable capacity and increase the amount
of dispatchable capacity, but room for improvement exists. As a
With approximately result of these changes, the percentage of megawatts contained
59 percent of the in nondispatchable contracts fell from an average of 71 percent
capacity still provided in the original portfolio to 59 percent on average in the
by nondispatchable renegotiated portfolio for the period from 2002 through 2010.
contracts, the During this same period, the dispatchable capacity increased
renegotiated contract from 38 percent of the portfolio’s megawatts in 2002 to
portfolio continues to 52 percent in 2010, as compared to an average of 29 percent in
lack the flexibility to the original portfolio. However, with approximately 59 percent
meet the hour-to-hour of the capacity still provided by nondispatchable contracts, the
variation in the net-short renegotiated contract portfolio continues to lack the flexibility
energy position. to meet the hour-to-hour variation in the net-short energy
position. As a result of this inflexibility, the potential for significant
sales of surplus energy continues to exist. For the year 2004, our
consultant has estimated that the surplus sales could be as much as
5,700 gigawatt-hours during peak hours, based on the department’s
current forecast of consumer demand.
TABLE 2
Net Change in Capacity Supplied by Long-Term Contracts
After Renegotiations (in Megawatts)
Calendar Year
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Dispatchable 142 892 2,625 1,770 1,995 920 920 790 790 1,090
Nondispatchable (165) 362 (818) (1,318) (1,468) (705) (690) (1,065) (1,065) (3,365)
Total for all contracts (23) 1,254 1,807 452 527 215 230 (275) (275) (2,275)
Source: Analysis by La Capra Associates using data provided by the Department of Water Resources.
Note: The amounts are the change in the type of capacity after renegotiations, and the total for the year is the change for the
portfolio as a result of the renegotiations. Capacities are for peak periods for July and August. A more detailed table is presented
on page 144.
2244 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2255
CHANGES IN FORECASTED DEMAND FOR POWER AND
CONTRACT RENEGOTIATIONS HAVE IMPROVED THE
NET-SHORT CAPACITY POSITION
In our December 2001 audit we noted that the department
consultant had determined the contracts in the original
portfolio would cover, on average, only about half of the net-
short capacity needed for the period 2002 through 2010, based
on then-current forecasts of peak demand. Net-short capacity
refers to the total capacity needed to cover the portion of the
peak demand for electricity that the investor-owned utilities
cannot produce. Because power cannot be stored in signifi cant
quantities for future use, system operators must have suffi cient
generating capacity operating at all times to meet consumer
demand. In Table 3, the Original Portfolio section shows that
even in 2004, when the capacity of the original portfolio is at its
maximum, only 58 percent of the projected net-short capacity
requirement is covered by the department’s contracts.
Since our December 2001 audit, the department’s consultant
has updated its analysis of the net-short capacity to refl ect the
effects of contract renegotiation and new forecasts of peak
demand, direct access, and conservation and load management.
The net result of this analysis is summarized in the Renegotiated
Portfolio section of Table 3, which shows
the required net-short capacity ranging from
approximately 12,200 megawatts in 2002 to
Elements of the Forecasted
Demand for Power 22,200 megawatts in 2010. For comparison,
the Original Portfolio section of Table 3 shows
• Peak demand—The greatest demand for
that the net-short capacity for the same period
power that occurs during a given time period.
ranges from approximately 17,100 megawatts to
• Utility-retained generation—The capacity 26,700 megawatts. As a result of this reduction
available from sources that the investor-
in the estimated net-short capacity required, the
owned utilities provide.
percentage of the projected peak demand covered
• Conservation and load management—
by the department’s contracts has increased
Energy conservation programs designed to
reduce the demand for power. considerably, especially during the period from
2002 to 2005, when the average coverage of the
• Direct access—A program that allowed
consumers to choose to directly contract for net short by the department’s contracts has risen
power from a power supplier, rather than to 67 percent or more. The Net Change section of
purchasing power from their local utilities.
Table 3 shows that the factors contributing to the
reduction in the net short are a reduction in the
forecast peak demand for electricity, an increase
in direct access by consumers, and a reduction in the amount
of demand carried over by discontinued conservation and load
management programs.
2266 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2277
TABLE 3
Forecasted Net-Short Capacity (in Megawatts)
Calendar Year
2002 2003 2004 2005 2006 2007 2008 2009 2010
ORIGINAL PORTFOLIO*
Peak Demand 43,105 44,093 45,100 45,541 46,517 47,550 48,541 49,494 50,289
Self-Generation (312) (543) (795) (1,059) (1,309) (1,545) (1,779) (2,014) (2,248)
Direct Access (355) (382) (395) (403) (1,713) (2,708) (2,961) (3,154) (3,183)
Utility-Retained Generation (19,753) (19,682) (19,386) (18,185) (17,535) (17,303) (16,569) (16,148) (15,924)
Conservation and Load
Management (5,536) (3,389) (2,777) (2,587) (2,617) (2,415) (2,201) (2,222) (2,238)
Net Short 17,149 20,097 21,747 23,307 23,343 23,579 25,031 25,956 26,696
Department Contracts (7,917) (11,046) (12,555) (11,680) (11,617) (11,602) (11,302) (11,302) (11,002)
Residual Net Short 9,232 9,051 9,192 11,627 11,726 11,977 13,729 14,654 15,694
Department Contracts as a
Percent of Net Short 46% 55% 58% 50% 50% 49% 45% 44% 41%
RENEGOTIATED PORTFOLIO†
Peak Demand 37,651 38,351 39,162 40,028 40,858 41,641 42,461 43,262 44,102
Self-Generation (121) (256) (365) (475) (548) (620) (696) (776) (860)
Direct Access (4,714) (4,714) (4,714) (4,714) (4,714) (4,714) (4,714) (4,714) (4,714)
Utility-Retained Generation (20,610) (20,772) (19,616) (18,782) (18,018) (17,636) (17,532) (16,660) (16,333)
Conservation and Load
Management (55) 0 0 0 0 0 0 0 0
Net Short 12,151 12,609 14,467 16,057 17,578 18,671 19,519 21,112 22,195
Department Contracts (8,407) (11,143) (11,332) (10,721) (10,446) (9,928) (9,628) (9,628) (7,328)
Residual Net Short 3,744 1,466 3,135 5,336 7,132 8,743 9,891 11,484 14,867
Department Contracts as a
Percent of Net Short 69% 88% 78% 67% 59% 53% 49% 46% 33%
NET CHANGE -13% -13% -13% -12% -12% -12% -13% -13% -12%
Peak Demand (5,454) (5,742) (5,938) (5,513) (5,659) (5,909) (6,080) (6,232) (6,187)
Self-Generation (191) (287) (430) (584) (761) (925) (1,083) (1,238) (1,388)
Direct Access 4,359 4,332 4,319 4,311 3,001 2,006 1,753 1,560 1,531
Utility Retained Generation 857 1,090 230 597 483 333 963 512 409
Conservation and Load
Management (5,481) (3,389) (2,777) (2,587) (2,617) (2,415) (2,201) (2,222) (2,238)
Net Short (4,998) (7,488) (7,280) (7,250) (5,765) (4,908) (5,512) (4,844) (4,501)
Department Contracts 490 97 (1,223) (959) (1,171) (1,674) (1,674) (1,674) (3,674)
Residual Net Short (5,488) (7,585) (6,057) (6,291) (4,594) (3,234) (3,838) (3,170) (827)
* Power Supply Revenue Bonds, Department of Water Resources, draft consultant report, July 2001, prepared by Navigant Consulting, Inc.
† Power Supply Revenue Bonds, Department of Water Resources, consultant report, October 2002, prepared by Navigant Consulting, Inc.
2266 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2277
The forecast peak demand for electricity has dropped by about
13 percent from the forecast that the department consultant
used to evaluate the original portfolio. The department
consultant attributes this reduction to the new energy
conservation programs begun in 2001, to changes made by
consumers in response to higher prices for power charged by
the investor-owned utilities, and to changes in power usage in
response to the energy crisis.
The increase in direct access load since the previous analysis
reflects the fact that customers who contracted to buy electricity
from alternate suppliers on or before the date that the CPUC
suspended the direct access program will continue to be eligible
for such service. As we noted in our December 2001 audit,
the CPUC order suspended all contracts for the direct access
program that were entered into after September 20, 2001,
instead of using a much earlier cut-off date, as the department
consultant had expected. The effect of this order is to reduce the
peak demand for power served by the contract portfolio because
the order allowed more customers than expected to remain in
contracts with alternate suppliers rather than receiving their power
from the three investor-owned utilities.
Finally, the reduction in conservation and load management
is explained by the fact that funding for all but one of these
programs was discontinued in 2002. The remaining program
is expected to provide a much lower reduction in energy
usage during 2002. However, the conservation and load
management initiatives undertaken in 2001 are expected
to provide continuing load-reduction benefits. According
to the department consultant, the reduction in demand
resulting from continuing conservation and load management
programs is included in the peak demand in the forecast for the
renegotiated portfolio shown previously in Table 3.
CONTRACT RENEGOTIATION EFFORTS HAVE REDUCED
THE OVERSUPPLY OF POWER IN SOUTHERN CALIFORNIA,
BUT RISKS REMAIN
Although the State’s renegotiation efforts have alleviated some
of the oversupply problem in Southern California, a substantial
surplus continues in that zone. Further, the renegotiation efforts
have had minimal impact on the need for additional capacity
to meet peak demand in Northern California. Our consultant
used the load duration curves shown in Figure 1 on page 30
2288 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2299
and Figure 2 on page 31 to analyze the fi t of the contract
portfolio before and after the contract renegotiations. A load
duration curve ranks the hourly customer demands for power
from greatest to least in a given period, such as a year. That is,
the highest or maximum hourly demand, which occurs in only
one hour of the year, is shown at approximately 0 percent on
the curve. In contrast, the lowest or minimum hourly demand
occurs at one hour of the year and is shown at approximately
100 percent (hour 8,760) on the curve. The highest load defi nes
the maximum operating generating capacity needed during
the year and determines the capacity requirement—the total
number of megawatts the generation system must be capable of
producing instantaneously to assure reliable supplies. There are
very few hours in the year when generation production must
be close to that level. The annual energy requirement is the
sum of the hourly loads over all of the hours in the year and is
expressed in terms of megawatt-hours.
In our December 2001 audit, we used a hypothetical load
duration fi gure to illustrate that while the department had
contracted for suffi cient energy to cover most of the net-short
energy required through 2010, it had acquired enough capacity
to cover only about half of the net-short capacity it would
require. We also noted that the net-short capacity needed was
subject to considerable variation, to which the department
would have to respond over time. This variation is the result
of changes in capacity contributions from the investor-owned
utilities’ own generation, changes in loads with the seasons,
and daily and hourly changes in loads as commercial facilities
initiate and close operations and residential customers switch
their home appliances on and off.
Our consultant’s load duration curve analysis for this audit
sought to determine (1) the remaining net-short capacity need
in megawatts that is not being met by the portfolio, (2) the
remaining net-short energy need in gigawatt-hours
that is not being met by the portfolio, and
(3) energy surpluses from nondispatchable contracts.
Peak Hours Versus Off-peak Hours
To determine only the changes that resulted from
Peak hours—Range from 7 a.m. to 11 p.m., contract renegotiations, the load duration curves for
the time when the demand for power is
before and after contract renegotiation use a demand
greatest in the day.
forecast prepared by the department consultant
Off-peak hours—Range from 11 p.m. to
in mid-2002, at the time of the department’s 2002
7 a.m., usually the time of least
power demand. revenue requirement fi ling. Further, our consultant’s
analysis was split between the peak and off-peak
hours of the day because the power needs as well
2288 California State Auditor Report 2002-009 California State Auditor Report 2002-009 2299
as the energy supplies available are different during these times.
The load duration curves use 2004 as a reference year because this
is the year that the capacity of the department’s portfolio is at its
maximum and, therefore, the year with the greatest potential for
energy surpluses. Figure 1 covers the zone south of Path 15 (SP15),
which includes the service areas of Southern California Edison and
San Diego Gas & Electric—basically Southern California. Figure 2
covers the zone north of Path 15 (NP15), which includes the
Pacific Gas & Electric service area—basically Northern California.
We have examined these regions separately because it is currently
not possible to transmit large amounts of power between the two
regions, due to limited transmission capacity.
The load duration curves use a red line to depict the consumer
demand for power during various hours of the year. The shaded
areas represent power deliveries from the contract portfolio—
marked by type of product—with shaded areas above the line
being surplus power that is not needed to meet forecasted demand.
FIGURE 1
Load Duration Curves for the SP15 Zone Before and
After Contract Renegotiation for 2004
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Source: Load duration analysis by La Capra Associates. To show only the change in power delivered from the contract portfolio, both
curves use a September 2002 demand forecast prepared by the Department of Water Resources’ consultant, Navigant Consulting, Inc.
3300 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3311
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This power would need to be disposed of, most likely at less than
the contract price. White areas under the red line represent capacity
that will need to be purchased to meet demand.
The Southern California load duration curves shown in Figure 1
indicate that, in that region, the department contracts will
provide most of the power needed to meet the regional net
short in 2004. Also, while the renegotiations have reduced
the amounts of surplus energy, significant amounts remain
in both peak and off-peak hours. Thus there is a need for the
department, the investor-owned utilities, and the CPUC—in
accordance with their respective roles—to carefully monitor
surplus power sales to minimize the cost to ratepayers.
FIGURE 2
Load Duration Curves for the NP15 Zone Before and
After Contract Renegotiation for 2004
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Source: Load duration analysis by La Capra Associates. To show only the change in power delivered from the contract portfolio, both
curves use a September 2002 demand forecast prepared by the Department of Water Resources’ consultant, Navigant Consulting, Inc.
Figure 2 compares the peak and off-peak load duration curves
for the NP15 zone before and after contract renegotiation. These
curves depict a different energy supply situation than the one
shown in Figure 1. In this region there is some surplus energy
3300 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3311
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at times, but not to the extent existing in Southern California.
Instead, there is a continued cost risk associated with the
additional capacity needed to meet peak demand, as shown by
the significant amount of white areas under the red line. During
these peak demand hours, spot market prices can spike, with
the resulting increased costs potentially passed on to ratepayers.
The State’s renegotiation efforts will have minimal impact on
the power deliveries to this zone in 2004, and thus the power-
procurement strategies that the investor-owned utilities use to
address this peak period risk will need close attention.
THE CHANGE IN FORECAST HAD A GREATER IMPACT
THAN RENEGOTIATION ON IMPROVING THE FIT OF
THE CONTRACT PORTFOLIO TO CONSUMER DEMAND
Table 4 summarizes the peak-hour capacity along with the
energy needs and energy surpluses displayed in the load
duration curves shown previously in Figures 1 and 2. In
addition, the table includes similar data for the original portfolio,
but using the 2001 forecast. In order to separate the effects of
contract renegotiation from the effects of the change in the
demand forecast, our consultant constructed two distinct load
duration curves for the before-contract-renegotiation scenario:
one based on the 2001 forecast and the other based on the
2002 forecast. To obtain the changes due solely to contract
renegotiation, we compared the results from the after-contract-
renegotiation scenario, which are based on the 2002 forecast,
with the results from the before-contract-renegotiation scenario
based on the 2002 forecast. In contrast, to obtain the changes due to
both contract renegotiation and the change in the demand forecast,
The projected energy we compared the results from the after-contract-renegotiation
surplus in the peak hours of scenario with the results of the before-contract-renegotiation
2004 has fallen by about scenario based on the 2001 forecast.
14,600 gigawatt-hours,
but only 5,300 gigawatt- These analyses reveal that the change in forecast had a
hours of this reduction was greater impact on improving the fit of the portfolio than did
due to the renegotiated contract renegotiation. For example, the energy surplus for both
contracts; the remainder the SP15 and NP15 zones in the peak hours fell from a total
was due to a reduction in of approximately 20,300 gigawatt-hours before renegotiation
forecasted demand. (shown previously as the shaded areas above the red demand
line in Figures 1 and 2, and the number in the column headed
2001 Market Assumptions in Table 4) to approximately
5,700 gigawatt-hours after renegotiation, a change of about 14,600
gigawatt-hours. However, the reduction in energy surpluses
due solely to contract renegotiation (shown in Table 4 as the
3322 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3333
TABLE 4
Estimated Capacity Need and Energy Surplus in 2004 Before and After Renegotiations
(Assumes no energy exchange between NP15 and SP15)
Peak Off-peak
Before After Before After
2001 Market 2002 Market 2002 Market 2001 Market 2002 Market 2002 Market
Total Assumptions Assumptions Assumptions Assumptions Assumptions Assumptions
Capacity need after nondispatchable
and dispatchable contracts
(in megawatts) 6,795 5,841 5,564 10,716 5,368 5,386
Energy need after nondispatchable
and dispatchable contracts
(in gigawatt-hours) 2,873 2,003 2,354 3,295 1,965 2,012
Energy surplus from
nondispatchable contracts
(in gigawatt-hours) 20,316 10,985 5,726 8,465 7,903 5,641
2001 Market 2002 Market 2002 Market 2001 Market 2002 Market 2002 Market
NP15 Assumptions Assumptions Assumptions Assumptions Assumptions Assumptions
Capacity need after nondispatchable
and dispatchable contracts
(in megawatts) 5,355 3,642 3,932 6,623 4,084 4,112
Energy need after nondispatchable
and dispatchable contracts
(in gigawatt-hours) 2,815 1,884 2,300 2,996 1,895 1,943
Energy surplus from
nondispatchable contracts
(in gigawatt-hours) 1,835 581 409 1,076 1,516 1,469
2001 Market 2002 Market 2002 Market 2001 Market 2002 Market 2002 Market
SP15 Assumptions Assumptions Assumptions Assumptions Assumptions Assumptions
Capacity need after nondispatchable
and dispatchable contracts
(in megawatts) 1,440 2,199 1,632 4,093 1,284 1,274
Energy need after nondispatchable
and dispatchable contracts
(in gigawatt-hours) 58 119 54 299 70 69
Energy surplus from
nondispatchable contracts
(in gigawatt-hours) 18,481 10,404 5,317 7,389 6,387 4,172
Sources: Load duration analysis of 2004 by La Capra Associates using contract-modeling data prepared by the Department of
Water Resources’ consultant, Navigant Consulting, Inc. The 2001 Market Assumptions are based on market information from
October 2001 and the 2002 Market Assumptions are based on market information from September 2002.
3322 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3333
difference between the approximate 11,000 gigawatt-hours in
the Before column headed 2002 Market Assumptions and the
approximate 5,700 gigawatt-hours in the After column headed
2002 Market Assumptions) is only about 5,300 gigawatt-hours.
Contract renegotiation had very little effect on the projected
2004 energy surpluses in Northern California, assuming a
scenario of no exchange between the two regions, but this
should not be a concern, given that the peak and off-peak
surpluses in that area are relatively small in comparison to those
in Southern California. Further, if the planned upgrade of the
transmission lines connecting Northern and Southern California
eliminates the existing transmission constraints, our consultant
indicates that the total energy surpluses could fall from about
5,700 gigawatt-hours to about 2,900 gigawatt-hours during peak
hours and from 5,600 gigawatt-hours to 4,900 gigawatt-hours
during off-peak hours. However, the transmission upgrade is not
expected to occur until late 2004 at the earliest, and thus it will
not be in place in time to alleviate the energy surplus in 2004.
Absent the replacement of more nondispatchable energy by
dispatchable capacity, our consultant expects that the energy
surpluses in the SP15 zone could continue for at least the next
several years. In addition, absent the purchase of additional
capacity, we expect that the need for additional peak-hour
capacity will continue in the NP15 zone throughout the life of
the contract portfolio. Thus the department, the investor-owned
utilities, and the CPUC—in accordance with their respective
roles—must carefully monitor the situations in each zone to try
to minimize the costs passed to ratepayers.
THE ADDITION OF MORE DISPATCHABLE CONTRACTS
HAS REDUCED THE POTENTIAL ENERGY SURPLUSES
IN SOUTHERN CALIFORNIA AND MET SOME OF THE
NEED FOR INCREASED CAPACITY AND ENERGY IN
NORTHERN CALIFORNIA
In our December 2001 audit, we noted that the capacity
contracted for delivery in Southern California from the fourth
quarter of 2003 through the first quarter of 2005 was expected
to exceed the average peak demands of consumers in that area,
resulting in significant energy surpluses and potentially higher
electricity rates because ratepayers will be charged for any loss
on sales of surplus energy. The department consultant expects
that the surplus will be either sold to out-of-state purchasers at
3344 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3355
a loss or exchanged with utilities in the Pacific Northwest, since
the energy needs of the two regions complement each other. As
we mentioned previously, the reason the expected mismatch of
loads and supplies in Southern California is a problem is that
there is insufficient transmission capacity to move surplus power
into Northern California to meet the needs of that area. Table 5
shows that the need for additional power supplies in Northern
California has been partially met, but only on a temporary basis,
by an increase in the capacity of contracts delivering power to
that area in 2002 and 2003.
TABLE 5
Net Change in Allocation of Contract Capacity Among Zones
After Renegotiations (in Megawatts)
Calendar Year
Zone 2001 2002 2003 2004 2005 2006–2010
NP15 (215) 1,327 1,140 (115) 110 (489)
SP15 192 (73) 667 567 417 14
Total for all contracts (23) 1,254 1,807 452 527 (475)
Source: Analysis by La Capra Associates using contract summary data from the Department of Water Resources.
Note: The amounts are the change in capacity for that zone after the renegotiations, and the total for the year is the capacity
change for the portfolio as a result of the renegotiations. Capacities are for peak periods for July and August. A detailed table is
presented on page 145.
Table 5 shows that in 2003 the amount of capacity in SP15
has increased by approximately 670 megawatts, falling to
420 megawatts by 2005. Since this increased capacity is from
dispatchable power—as noted previously in Table 2—it will not
exacerbate the energy surplus in that zone but rather should
help address the remaining peak-hour need.
ALTHOUGH THE DEPARTMENT’S PORTFOLIO HAS BEEN
ENHANCED BY THE ADDITION OF MORE TOLLING
CONTRACTS, THE RISK OF GAS PRICE INCREASES MUST
BE MANAGED
During 2001 the department signed a number of power supply
agreements that incorporated tolling agreements, but our
December 2001 audit concluded that it could have procured
more tolling agreements to allow for better control of gas
costs. A tolling agreement is a contract by which the owner of
3344 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3355
a generating facility is paid to “convert” a fuel supply, such as
natural gas, to electricity for delivery to a power supply buyer.
In a tolling contract, Tolling agreements typically specify that the generating facility
the power buyer, such owner will supply fuel, then charge the buyer for fuel costs
as the department, is according to some contractually determined price (these often
responsible for the fuel rely on market indices). Some tolling agreements offer buyers the
supply and for buying the option of purchasing the fuel supply directly from fuel suppliers.
service of converting the Thus, the main difference between a tolling contract and a power-
fuel into electricity. purchase contract lies in who pays for the fuel used to generate
the power. In a power-purchase contract, the power supplier is
responsible for the fuel supply and assumes any risk involving fuel
availability and price. In a tolling contract, the power buyer, such
as the department, is responsible for the fuel supply and for buying
the service of converting the fuel into electricity.
In taking responsibility for the fuel supply, the buyer acquires
the ability to negotiate with fuel suppliers over price and to
determine the appropriate level of fuel price variability for
consumers. That is, the power buyer could choose to pass all
changes in fuel costs through to consumers, which would mean
that power costs would increase when fuel prices increase and
decrease when they fell. Alternatively, since fuel prices are
among the most volatile of all commodities, the power buyer
could adopt a procurement strategy that involves entering
into financial contracts to better balance the potential benefits
and costs of volatile fuel markets. Financial contracts, such as
forwards, futures, and options contracts, transfer risk, especially
price risk, to those who are able and willing to bear it. If used
effectively, financial contracts can mitigate the cost risk to
consumers of large price swings.
Despite the fact that most of the energy for which the department
contracted is generated by natural gas-fired power plants, only
between 36 percent and 45 percent of the original contract
capacity for each year after 2001 contains terms that allow the
price of electricity to float with changes in natural gas prices.
Thus our December 2001 audit concluded that the original
portfolio does not provide consumers the opportunity to benefit
meaningfully from falling gas prices and that the department
should have procured more tolling contracts, particularly since its
consultant was projecting a reduction in natural gas prices from
the record high levels of late 2000 and early 2001.
With the renegotiation of some contracts, the capacity in
the portfolio associated with tolling contracts has increased
considerably. As Table 6 shows, the capacity from tolling
contracts has increased by more than 2,000 megawatts above
3366 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3377
that in the original portfolio for the period from 2003 to 2010.
If properly managed, this increase will provide more control
over fuel costs associated with the portfolio. While this change
has increased the opportunity for consumers to benefit from
lower natural gas prices, it also means that consumers bear the
risk of higher gas prices. Indeed, given that natural gas prices
have fallen well below the record levels of late 2000 and early
2001, when the contracts were first negotiated, the likelihood of
future significant price reductions is smaller than the likelihood
of significant price increases. In October 2002 the department
consultant projected that natural gas prices will increase by
approximately 50 percent by 2011. Now that the investor-owned
utilities are managing the fuel costs for these contracts, the
department and the CPUC—in accordance with their respective
roles—will need to be vigilant to ensure that each investor-
owned utility adopts a procurement strategy to minimize the
risk that ratepayers will be subjected to higher electricity rates
due to surges in natural gas prices.
TABLE 6
Net Change in Capacity of Tolling and Indexed Price Contracts
After Renegotiations (in Megawatts)
Calendar Year
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Tolling and indexed price* 232 1,142 2,920 2,065 2,490 2,265 2,265 2,135 2,135 2,135
Fixed price (255) 112 (1,113) (1,613) (1,963) (2,050) (2,035) (2,410) (2,410) (4,410)
Total for all contracts (23) 1,254 1,807 452 527 215 230 (275) (275) (2,275)
Source: Analysis by La Capra Associates using contract summary data from the Department of Water Resources.
Note: The amounts are the change in the capacity for that contract type after the renegotiations, and the total for the year is the capacity
change for the overall portfolio as a result of the renegotiations. Capacities are for peak periods for July and August. A detailed
table is presented on page 146.
*Power-purchase contracts containing an indexed variable fuel cost component or provides an opportunity for the buyer to
purchase fuel.
THE DEPARTMENT HAS REASONABLY CONTROLLED
ITS GAS COSTS, BUT SIGNIFICANT CONCERNS REMAIN
FOR THE FUTURE
As we noted previously, certain of the department’s long-term
contracts have gas tolling provisions that allow it the option of
purchasing natural gas directly, instead of paying a fixed price
to the seller. In the latter half of 2001 and 2002, the department
developed and implemented a strategy for managing gas costs
under these tolling agreements. We found that the department’s
3366 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3377
gas purchases and financial hedging activities under tolling
agreements for which it had gas procurement rights brought its
overall gas supply costs roughly into line with gas market prices
during 2002. The important gas procurement issues facing the
department in coming years are discussed in Chapter 6.
During the Latter Part of 2001 and 2002, the Department
Developed and Implemented a Strategy to Manage the Cost
of Fuel for Tolling Agreements
When the department began its role of purchasing electricity to
meet the net short, it initially paid relatively little attention to
managing the tolling provisions of its power-purchase contracts.
In particular, during the first six months of 2001, we found no
evidence that the department made gas supply purchases or
implemented financial hedges to control gas supply costs under
tolling agreements in which it had gas purchase rights. However,
the department was obviously aware of the benefits of using tolling
agreements with gas procurement rights to manage fuel costs, since
it had included such tolling agreements in the contract portfolio.
Department records reflect that several months after its purchase
obligations under long-term contracts had started, it began to
develop a strategy for purchasing gas and managing its gas-
related assets. Among the initial steps was the formation of a
Fuel Management Working Group, as discussed in a June 2001
Gas Business Plan document. This plan indicates that the Fuel
Management Working Group was to include department staff
and outside consultants with considerable experience in the
natural gas industry and specific experience in the California
market. The Fuel Management Working Group was directed to
perform two basic functions: (1) undertake strategic planning
for the purchase of fuel supplies and (2) implement those plans.
The strategic planning focused on assessing the natural gas
market and developing recommendations regarding the overall
gas purchase strategy, the appropriate fuel product mix, and
the tools necessary to meet gas supply needs. To implement
these plans, the department would sign agreements not only to
purchase gas supplies but also to transport gas on interstate and
local pipeline systems and to access fuel storage facilities to hold
the gas until needed. Contracts in effect during 2001 offering
the department a fuel purchase option included the Dynegy,
GWF, Alliance, and Sunrise contracts.
Department documents suggest that it took some months for
the Fuel Management Working Group to begin making gas
purchase transactions. As we discuss in greater detail later, gas
3388 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3399
cost data provided by the department indicate that it did not
begin to engage in third-party gas supply transactions until
July 2001. Moreover, a February 2002 department memorandum
introduced an approved Fuel Management Program, identified
the mission and objectives of this effort as being to exercise
gas purchase rights under certain tolling agreements, and
designated certain individuals as members of the fuels team. The
memorandum also indicates that the Fuel Management Program
by then included a risk management component (that is, financial
hedging) to assist in meeting established fuel cost objectives.
A potential impediment to the department’s efforts to manage
fuel costs was its concern that Assembly Bill 1 of the 2001–02
First Extraordinary Session (AB 1X) would not allow it to engage
in price hedging activities—such as the use of gas futures and
options contracts—to mitigate the risk of cost increases due
In December 2001 the to rising gas prices. However, in December 2001 the attorney
attorney general opined general provided the department an opinion indicating that the
that the department department had the legal authority to engage in transactions to
had the legal authority hedge gas supply prices. Subsequently, the department established
to engage in financial an account with a brokerage firm in mid-2002 with a balance of
hedging activities $10 million to allow it to engage in financial hedging transactions.
for managing gas
supply prices. An example of how the department implemented this hedging
strategy was its management of gas for its Dynegy contract.
Its gas procurement strategy suggested that 30 percent of
anticipated baseload gas supply requirements under the contract
be purchased six months in advance, another 30 percent three
months in advance, 20 percent in the prior-month market, and
the remaining 20 percent in the daily spot market for gas. The
use of financial hedges to lock in or limit gas procurement costs
was also recommended.
Documents submitted by the department to the CPUC in
spring 2002 offer a view of fuel supply activities, describing
specific objectives for the department’s gas purchase program
and identifying the activities of the fuels team. These activities
included weekly meetings to review market conditions,
discuss the ongoing gas procurement and hedging plan,
review gas supplier performance, and address other related
issues. A detailed list of activities also addressed the fuels
team’s involvement in entering into gas purchase agreements,
acquiring financial hedging tools, and so on. Other department
documents reveal that the department’s gas procurement and
gas hedging activity extended into January 2003 to ease the
transition to the investor-owned utilities.
3388 California State Auditor Report 2002-009 California State Auditor Report 2002-009 3399
The Department’s Gas Procurement and Gas Price Hedging
Activity Increased During 2002
Figure 3 provides a perspective on the department’s gas tolling
opportunity during 2002 and its expectations for 2003. It
illustrates the combined maximum capacity of the department’s
gas tolling agreements during peak hours for a given month,
broken down into the capacity contributed by contracts with a
gas purchase option and those without such an option, where
the risk of changing gas prices is assigned through a formula in
the contract. As shown, the number of megawatts covered under
the department’s tolling contracts that have a gas purchase
option continued to increase during 2002. As Table 6 on page 37
indicated, contract renegotiations have increased the capacity
of tolling agreements in the portfolio. By December 2002, the
department had power supply contracts with seven entities
that included tolling agreements with gas purchase rights,
representing approximately 3,100 megawatts.
FIGURE 3
2002 and 2003 Gas Tolling Agreements With and Without Gas Purchase Option
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Source: La Capra Associates’ analysis of contract data from the Department of Water Resources.
4400 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4411
����������������������
During 2002 the department’s gas purchase activities focused on
three of its power supply contracts. The department’s physical
gas purchases were made largely for the Dynegy and Sunrise
contracts. These gas purchases totaled just over 41 million MMBtus
(million British thermal units) during the year, with a value of
roughly $141 million. A gas-fired generation facility will typically
require between 7.5 to 13 MMBtus of natural gas to produce one
megawatt-hour of electricity, depending on its efficiency.
Beginning in July 2002, the department also engaged in financial
hedging activity to manage gas costs. Department records reflect
that its hedging activity included transactions related to its
Dynegy contract. Calpine represented a third important contract
that was a focal point of the fuels team’s efforts. However, the
department indicates that it did not initially make physical
gas purchases for the Calpine contract during 2002 because it
observed that the gas prices that Calpine charged were generally
consistent with market prices. In late 2002, the department made
some physical gas purchases for the Calpine contract as a result of
financial incentives offered by Calpine.
The Cost of Gas Purchased by the Department Under the
Tolling Contracts Was in Line with Natural Gas Market Prices
by April 2002
By April 2002 the department’s gas purchase and financial
hedging activities for tolling agreements with a gas purchase
option resulted in gas costs that were roughly in line with
market prices. The Dynegy and Calpine contracts were the
most significant tolling agreements with gas purchase rights in
the department’s portfolio during the year. After the Calpine
contract took effect in mid-2002, the department identified the
combined gas needs under the two contracts as roughly 275,000
MMBtu per day.
Figure 4 on the following page presents a view of the department’s
gas costs, including physical purchases and financial hedging,
for those two contracts. This figure contains three lines. The first
line shows the department’s market price index, which climbed
from just under $2.25 per MMBtu in January to almost $4.25
per MMBtu by December. The second line shows the weighted
average cost of gas for the Dynegy and Calpine contracts. This
line reveals that weighted average gas costs were above market
by as much as $1 per MMBtu during early 2002, indicating that a
previous effort by Dynegy to purchase gas in advance resulted in
4400 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4411
ratepayers paying more in fuel costs than if the forward purchase
had not occurred. The department indicated that this was largely
the result of forward purchase commitments made during 2001,
when gas price expectations were higher. By April 2002, however,
the department’s weighted average gas costs were very close to its
market index, and they remained there through the rest of the
year. The third line in Figure 4 begins in July 2002—the month
when the department began its financial hedging activities—and
reflects (on a monthly basis) the resulting costs and cost savings
to the department.
FIGURE 4
2002 Gas Costs Versus Market Price
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Sources: La Capra Associates’ analysis of data provided by the Department of Water Resources. The market price line is from
Gas Daily or Department of Water Resources’ estimates.
4422 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4433
���������������
In addition to its 2002 activities described above, the
department was able to reduce gas costs during 2001 by using
its right to purchase gas under the Dynegy tolling agreement.
This agreement allows Dynegy to pass gas costs through to the
department or, alternatively, allows the department to purchase
the gas for Dynegy. After the department’s fuel team was
formed, it reviewed the gas costs in the invoices from Dynegy
and observed that they were roughly $500,000 to $1 million per
month above levels consistent with prevailing market prices.
Once the department began purchasing a portion of the gas
requirements for the Dynegy contract in October 2001, Dynegy’s
invoiced gas costs began to move closer to market prices. n
4422 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4433
Blank page inserted for reproduction purposes only.
4444 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4455
CHAPTER 2
While the Renegotiation Effort Will
Provide Some Savings to Ratepayers,
the Department’s Portfolio Still Remains
Above Market Prices
CHAPTER SUMMARY
The contract renegotiation efforts have reduced the costs
to the Department of Water Resources (department) of
its portfolio of long-term power contracts. The savings
resulting from the renegotiated contracts can be calculated in
a variety of ways, each with some merits and each with some
limitations. Throughout the energy crisis, the department and
the governor’s office reported both the contract costs and the
savings in terms of the contact payments to suppliers. Thus,
they reported that the reductions in contract costs from the
restructuring of the contracts totaled approximately $5.5 billion,
which represents approximately 13 percent of the total original
contract costs of $42.9 billion. These contract cost reductions
were based on information available at the time of the
renegotiations and were calculated using a negotiation model
that the department used when evaluating the effect of different
renegotiation options on the reduction in contract costs.
While this savings estimate reasonably reflects cost reductions
in the nominal value of the contract portfolio, an alternative
analysis would estimate the savings to the consumer by taking into
account the cost to replace the power that was eliminated through
renegotiations. The department consultant performed this analysis
during the renegotiations, using its negotiation model, and, at our
request, in March 2003, using its revenue requirement model for
estimating portfolio costs. When estimating what ratepayers may
pay to replace the power that was eliminated from the contracts,
the department consultant’s calculations show that the net
savings to ratepayers in nominal terms is currently estimated to be
$1.5 billion. Also, because these savings will occur over the next
20 years, the department consultant calculates that the net present
value of the future stream of savings to ratepayers is currently
estimated to be $580 million. During the renegotiations, the
department consultant also performed net present value analyses
of the estimated contract cost reductions and ratepayer savings for
individual contracts.
4444 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4455
These March 2003 estimates of customer savings are a function
of economic, market, and dispatch assumptions used by the
department consultant in its modeling and would change if
those assumptions were changed. Also, the department indicates
that its revenue requirement model is not designed to value
nonprice benefits resulting from the renegotiation efforts,
such as the improved availability and reliability provisions in
the contracts discussed in Chapter 3. Further, most of these
contract cost reductions will result not from reducing the
price per megawatt-hour of the power purchased but rather
from shortening the length of the contracts or reducing the
amount of power to be delivered. In other words, the contracts
will continue to deliver high-cost power—power that is priced
significantly above forecasted spot market prices—just less of it.
However, this reduction of contract length contributed to one
of the department’s objectives, which was to shorten the time
period for which it would have financial or legal responsibility
for the contracts and, in the process, permit the utilities to procure
energy themselves to meet the additional uncovered net short.
The department had not intended to estimate the savings
to ratepayers that resulted from the contracts that were
renegotiated through December 31, 2002. According
to the department, the March 2003 estimate of savings
to the consumer from the renegotiated contracts as of
December 31, 2002, using the revenue requirement model,
was made only at our request, and the department would not
otherwise have made this calculation. In addition, the amounts
are from its consultant’s draft report, and as of March 17, 2003,
the amounts had not gone through the department’s ordinary
standards of review for reports of this nature. However, this
is the only estimate the department provided to us of the
savings to the consumer from the renegotiated portfolio
as of December 31, 2002. Further, we observed that these
forecasts are consistent with the forecasts prepared by the
department in establishing its revenue requirements, and its
models and assumptions have been reviewed by the California
Public Utilities Commission (CPUC) and many others in the
development of those forecasts. These forecast methods were
also used by the department consultant in the consultant’s
report provided in support of the revenue bonds that the
department issued in October and November 2002.
4466 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4477
BY THE END OF 2002, REPORTED COST REDUCTIONS
ASSOCIATED WITH THE RESTRUCTURING OF THE 22 LONG-
TERM POWER CONTRACTS TOTALED $5.5 BILLION
As we discussed in our December 2001 audit, the crisis during
which the department entered into these contracts led to a power
portfolio that presented significant cost risks needing careful
management. After the crisis began to ease, the department in fact
began to address many of these risks, implementing some of the
audit recommendations. The department consultant indicates that
in late 2001, a negotiating team approached various suppliers about
restructuring the power contracts signed in 2001, and initially at
least one supplier was responsive.
The State restructured 23 contracts with 14 of its 29 suppliers in
2002. Following the announcement of the renegotiation of the
Sunrise Power contract on December 31, 2002, the total reported
reductions in contract costs were estimated at approximately
$5.5 billion. Table 7 provides a list of the renegotiated contracts and
the resulting reductions in committed expenditures, as reported in
state press releases.
TABLE 7
Reported Reduction in Contract Costs Resulting
From Renegotiations (in Millions)
Contract Contract Cost Reductions
Cabazon $ 20
Calpine 2,990
Capitol Power 6
High Desert 560
Whitewater Hill 31
Calpeak 71
Soledad 2
GWF 215
Colton Power (formerly Alliance) 15
PG&E 3
Williams 1,400
Clearwood 28
Santa Cruz 2
Wellhead Power 8
Sunrise 121
Total $5,472
Source: Press releases from the governor’s office and the Department of Water Resources.
Because a range of reductions were reported for Cabazon and Whitewater Hill, we used
the mid-point of the reductions for this table. In December 2002, the department reported
that the total contract cost reductions were $5.2 billion, but the individual amounts add to
approximately $5.5 billion in the table.
4466 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4477
The department’s original contracts with the 14 suppliers
previously listed in Table 7 represented a cost obligation that
totaled about $24 billion over the life of the contracts—over
half of the department’s entire portfolio—or, in present value
terms, about $14.5 billion, according to estimates made by the
department during the renegotiations.
The department also renegotiated other nonprice terms and
conditions that do not directly affect contract price. Many of
these provide greater reliability in energy supply. For example,
new provisions have been added to ensure that power plants
are built according to agreed-upon schedules. The restructured
contracts also provide greater flexibility in the dispatch of
The department also energy, allowing the department to call upon a particular
renegotiated other supplier’s resources within shorter time frames. While the
nonprice terms and value of such new or revised provisions is not captured in the
conditions that do not reported $5.5 billion in estimated contract cost reductions, they
directly affect contract clearly provide value to the State. The department indicates
price and cannot be that the models it uses to estimate contract cost reductions do
easily quantified in terms not value these nonprice changes to the renegotiated contracts.
of savings, but they For a more detailed discussion of the significance of these
clearly provide value to nonprice terms and conditions and how they improved the
the State. energy products in the contracts, see Chapter 3. The remainder
of this section focuses on the specific terms and conditions that
resulted in the reported $5.5 billion contract cost reductions.
The reported contract cost reductions represent reductions in the
expected payments to suppliers as a result of renegotiations. As
discussed in Chapter 1, many of the contract changes involved
converting fixed-price, nondispatchable energy products to
dispatchable products, some of which are gas tolling agreements.
Therefore, estimates of future payments for these renegotiated
contracts depend on fuel price expectations. Any cost reductions
resulting from such changes would be determined by the
difference between payments for the original nondispatchable
product and payments for the new dispatchable product.
Because a dispatchable product allows the department to choose
whether to take energy from the contract or instead purchase
from the energy market, the payments made to a supplier of a
dispatchable contract also depend on expected market prices
of energy relative to contract prices. Expected future market
prices, in turn, depend on a myriad of factors, principally fuel
prices, future demand for electricity, and future construction
of power plants and transmission lines. Therefore, in order to
estimate the expected payments to suppliers—and the contract
4488 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4499
cost reductions as a result of renegotiations—the department
and its consultants developed a negotiation model that
allowed for the analysis of the potential savings resulting from
the renegotiation of an individual contract. The department
indicated that it used the negotiation model to analyze changes
in an individual contract assuming that the remainder of the
portfolio remained constant in order to produce results quickly
to permit analysis of the different renegotiation options being
considered. The department and its consultant have a revenue
requirement model that they use to analyze portfolio changes,
but they indicated that running and validating the results using
this model can take days to weeks, and thus it could not be
responsive to the fast pace needed to make decisions during the
contract renegotiation process.
The reported contract cost reductions as shown in Table 7
on page 47 were largely based on the results from the
negotiation model used during the contract renegotiations,
which used market assumptions developed in fall 2001.
However, the department indicates that market conditions
have changed somewhat since the negotiations were completed
in December 2002 and the results in Table 7 were derived. To
reflect these changes and at our request, the department used
the negotiation model to conduct a similar analysis based on
assumptions representative of market conditions in the first quarter
of 2003. The results of this analysis are shown in Table 8 for the
three renegotiated contracts with the largest reported savings.
TABLE 8
Estimated Contract Cost Reductions of
Selected Renegotiations (in Millions)
Contract Per Original Analysis Per March 2003 Analysis
Calpine $2,486 $2,283
Williams 1,003 621
High Desert 1,167 1,063
Source: The Department of Water Resources’ consultant, Navigant Consulting, Inc.
These estimates do not match those in Table 7 due to omissions and inconsistencies
in cost reductions between the reported amounts and the supporting documentation
provided by Navigant Consulting.
4488 California State Auditor Report 2002-009 California State Auditor Report 2002-009 4499
As shown previously in Table 8, the March 2003 analysis results
in smaller contract cost reduction estimates for these contracts,
resulting from the changed market conditions reflected in this
analysis. These March 2003 estimates of savings are based on
current economic, market, and dispatch assumptions used by
the department consultant.
Our consultant indicates that the March 2003 analysis includes
assumptions that reflect higher demand for electricity and
fewer power plants being constructed than in the original
analysis. This combination of higher demand and lower supply
results in higher forecasted market prices for energy. All else
being equal, higher market prices will result in the department
choosing to take more energy from its dispatchable products,
thereby increasing payments to suppliers and lowering the
cost reductions under the renegotiated, dispatchable contracts,
relative to the prior analysis. Further, both the renegotiated
Calpine and High Desert contracts involved gas tolling
agreements. Because the 2003 analysis included a higher
gas price forecast, this further increases the cost of these
renegotiated contracts and lowers the cost reductions. While
these estimates, reflecting more recent market conditions,
were not available to the negotiators during the process
of renegotiations, the negotiators were provided with cost
reduction estimates based on market conditions at that time.
Cost Reductions in Contracts May Not Translate to Lower
Electricity Bills, Due to the Cost of Replacement Power
The estimated contract cost reductions noted previously
represent reductions in the total amount of power purchased
and, as a result, reductions in payments to suppliers over
Much of the power the lives of the restructured contracts. However, because the
no longer supplied as restructured contracts also result in fewer power purchases
a result of contract compared to the original contracts, the cost of the power that
renegotiations must be will be procured to make up for this reduction in purchases
replaced to meet demand, (replacement power costs) must be taken into account when
thus the cost of the determining actual savings to ratepayers.
replacement power must
be taken into account Much of the power no longer supplied to the department as
when determining actual a result of contract renegotiations, while high priced, was not
savings to ratepayers. surplus, particularly in instances where negotiations led to
reductions in contract lengths. Replacement power, presumably
at more favorable market rates, will be required to supply the
portion of the net short that would otherwise have been met
by this contract power. While the department will not purchase
5500 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5511
that replacement power and will not incur the costs of that
power, ratepayers will bear the costs that the utilities incur in
their procurement of that replacement power from alternate
suppliers. This additional cost to ratepayers will partially offset
the savings that ratepayers will realize from the contract cost
reductions. It is the net result of these effects—the amount of
contract cost reductions less the amount that must be spent by
the utilities to purchase replacement power—that will ultimately
determine the net effect on ratepayers’ bills.
The following example illustrates this point. Suppose that as part of
the renegotiations, a supplier agrees to eliminate the department’s
obligation to purchase 100,000 megawatt-hours of power at $75 per
megawatt-hour in a given time period. Suppose also that the
department anticipated it will still need 60 percent of that power
to meet electricity demand during that time. If the department
believes the market price of power during that time will be, say,
$50 per megawatt-hour, ratepayer savings associated with the
elimination of these purchases will be as shown in Table 9.
TABLE 9
Hypothetical Ratepayer Savings When
Replacement Power Costs Are Considered
Original Contract Restructured Contract
Cost of contract $7,500,000 $0
(100,000 megawatts at
$75 per megawatt-hour)
Cost of replacement power $0 $3,000,000
(60,000 megawatts at
$50 per megawatt-hour)
Total ratepayer cost $7,500,000 $3,000,000
Ratepayer savings $4,500,000
($7,500,000 - $3,000,000)
Source: La Capra Associates’ analysis.
Ratepayer savings are highly dependent on projections of future
market prices for power. If, for instance, the department altered
its projections of future market prices from $50 per megawatt-
hour to, say, $70 per megawatt-hour, ratepayer savings in the
example described would be reduced from the $4.5 million
shown in Table 9 to $3.3 million.
5500 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5511
A closer look at the reduction in expenditures achieved as a
result of the contract renegotiations reveals the importance of
considering replacement power costs. Our analysis focused on the
contract cost reductions associated with five of the renegotiated
contracts—Calpine, Williams, High Desert, GWF, and Sunrise—
because the renegotiations with these five suppliers account for
more than 95 percent of all cost reductions resulting from the
23 restructured contracts. Cost reductions associated with these
restructured contracts arise from four principal types of contract
changes, which can generally be categorized as follows:
• Changes in contract term. In many instances, contract lengths
were shortened to reduce the cost. For example, a 20-year contract
with Calpine was shortened to a 10-year contract. Shortening
this contract reduced the cost by effectively reducing the amount
of power purchased as well as avoiding capacity charges—fixed
payments for making a power facility available to provide power
to the department—for the canceled part of the contract.
• Reductions in the quantity of power purchased. Some
restructured contracts call for purchasing less power than the
original contract.
• Changes in product type. This change often involves
the conversion of a nondispatchable energy purchase to a
dispatchable purchase, allowing the department to take energy
only when needed. It could also mean converting a contract to
a tolling agreement, allowing the buyer to manage fuel costs.
• Reductions in price. In some instances, the changed
contract provisions reduce the price paid per megawatt-hour
purchased without altering the quantity of power or type of
product purchased.
Figure 5 shows the reported cost reductions from the five largest
restructured contracts divided into the categories just described.
The second and third categories—reductions in the quantity of
power purchased and changes in product type—are combined
into one in the figure.
As the figure shows, the vast majority of the reported cost
reductions—approximately $4.1 billion—result from the first
category, reductions in the length of the contracts. Changes in
product type and quantities purchased produce $900 million
in cost reductions. Another $200 million of the cost reductions
comes from direct price reductions.
5522 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5533
FIGURE 5
The Vast Majority of the Reported $5.5 Billion Contract Cost
Reductions Results From Reductions in the Length of Contracts
(in Billions, Nominal)
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Source: La Capra Associates’ analysis of the renegotiated contracts.
Note: Data shown does not sum to $5.5 billion due to rounding. “Other” refers to the
cost reduction with the other nine suppliers. We did not split out these expenditures
because the amounts were immaterial in comparison to the cost reductions for the five
largest suppliers.
Only reductions in price have a direct effect on ratepayers’
bills without requiring consideration of replacement power
costs. Every dollar in reduced payments to suppliers as a
result of direct price changes is a $1 less that the department
pays for power and is hence a $1 reduction in ratepayers’
bills. Reductions in contract quantities, while leading to large
decreases in payments to suppliers, require the consideration
of the need to buy replacement power to understand the net
impact on ratepayer savings. The same principle also applies to
reductions in the length of a contract—in both instances the
quantity of power purchased is reduced, but some or all of the
power must be replaced to cover the net short. However, if the
cost of contract power is significantly above market prices—as
in the case of the department’s contracts, reducing the amount
of power purchased can actually save the consumer more than a
reduction in the cost per megawatt-hour purchased.
5522 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5533
Because the vast majority of the reported $5.5 billion estimate
of the reduction in payments to suppliers requires consideration
of replacement power costs, these costs will have a large impact
Any accurate estimate on the ultimate ratepayer savings. Estimates of replacement
of replacement power power costs are necessarily dependent on future market prices,
costs must be estimated as illustrated by the hypothetical example in Table 9 on page 51,
on a total portfolio basis as well as on future demand for electricity, which will determine
and also consider other how much power must be replaced. Any estimate of replacement
economic factors such power costs will therefore involve considerable uncertainty.
as projected market
prices and future Estimating replacement power costs also involves considering all
demand for electricity. of the department’s energy resources to determine, at any given
time, how much power the department’s portfolio of contracts
obligates it to take and how much power is actually needed to
meet the net short. In other words, the department’s replacement
power costs must be estimated based on the entire portfolio. The
negotiation model that the department and its consultant used
to respond to the fast pace of the renegotiations could compute
a rough estimate of the ratepayer savings for an individual
contract, but it could not make this estimate in aggregate for
the entire portfolio. That is, the negotiation model could only
examine the effects of each individual contract in isolation,
without considering the remainder of the portfolio. The revenue
requirement model can estimate ratepayer savings for the entire
portfolio, but as we noted previously, the department indicates
that it needs days to weeks to produce this estimate.
The Department Consultant’s Latest Estimates Show That
Contract Renegotiations Are Currently Estimated to Save
Ratepayers About $1.5 Billion Over the Next 20 Years, Which
in Present Value Terms Is Roughly $580 Million
In 2003 the department consultant used the revenue
requirement model to estimate the replacement power costs
for the entire renegotiated portfolio as of December 31, 2002.
The department consultant’s estimate is based on market
assumptions revised in the first quarter of 2003, consistent with
those used to develop the contract cost reductions shown in
the second column of Table 8 on page 49. The results from the
revenue requirement model show that estimated total contract
cost reductions are approximately $4.8 billion and that the total
cost to replace power associated with the renegotiated contracts
is estimated to be about $3.3 billion. Ratepayer savings—the
difference between contract cost reductions and replacement
power costs—are currently estimated to be about $1.5 billion.
5544 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5555
It should be noted that the department consultant’s estimates
of contract cost reductions and ratepayer savings are highly
dependent on expected future market conditions. The estimate
of $1.5 billion in ratepayer savings reflects changes in market
conditions since the department negotiated the restructured
contracts, as well as the use of a sophisticated modeling tool
that considers the effects on the entire portfolio of all of the
renegotiations. Therefore, this estimate was unavailable to the
department during the renegotiations.
The estimate of $1.5 billion in ratepayer savings will accrue over
the life of the original contracts, which extends over the next
20 years. This estimate provides no indication of how quickly
or slowly these savings will be passed on to ratepayers. Clearly,
receiving $1.5 billion 10 years from now is much less valuable than
receiving it all now. Therefore, calculating the savings in present
value terms, as opposed to nominal terms, provides a more accurate
indication of the true value to ratepayers. Further, when making
Ratepayer savings will decisions regarding power purchases, utilities generally evaluate the
accrue over the next costs in present value terms so that alternatives covering different
20 years, thus calculating numbers of years can be evaluated in equal terms.
the savings in present
value terms, as opposed to The present value of a sum of money to be received in the future
nominal terms, provides is the amount that would have to be invested today at a given
a more accurate indicator rate of return (referred to as the discount rate) to be equivalent to
of the true value of the a future stream of payments. For instance, given a rate of return of
savings to ratepayers. 9 percent, California ratepayers could invest about $660 million
today and receive roughly $1.5 billion 10 years from now. This
amount is considered the present value of a $1.5 billion payment
in 10 years, given a discount rate of 9 percent.
Presenting both the estimated contract cost reductions and the
estimated ratepayer savings in present value terms is especially
important given the characteristics of many of the renegotiated
contracts. In particular, the restructuring of the three contracts
with the largest reported cost reductions—Calpine, Williams,
and High Desert—all involved reductions in contract length
as well as additional purchases in the near term, particularly
in 2002 through 2003. The value of such restructuring varies
significantly depending on whether it is expressed in nominal or
present value terms.
The department consultant did conduct an analysis of the
estimated present value of contract cost reductions and ratepayer
savings as the renegotiations were occurring. Using this analysis,
Table 10 on the following page shows the difference when contract
cost reductions are considered on a nominal and present value basis
5544 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5555
for the Calpine contract, the restructured contract with the largest
reported cost reductions. Because the vast majority of cost savings
for this contract will not be realized until 2010 and beyond, they
decline dramatically when considered on a present value basis. The
Calpine contract cost reduction of approximately $2.5 billion drops
to $1.3 billion and $820 million when expressed on a present value
basis at a discount rate of 5 percent and 9 percent, respectively.
TABLE 10
Calpine Contract Changes and Their Present Value Reductions in Contract Cost
(in Millions)
Present Value at Present Value at
Nominal 5 Percent 9 Percent
End-of-term changes
Elimination of 7x24 nondispatchable energy in 2010 and 2011 $2,095 $1,319 $925
Elimination of 10 years (2011—2021) of dispatchable energy 800 387 225
Totals 2,895 1,706 1,150
Additional purchases in 2002 and 2003 (398) (371) (352)
All other contract changes (11) 11 22
Net reductions in cost $2,486 $1,346 $820
Percent change -46% -67%
Sources: La Capra Associates’ analysis of data from the Department of Water Resources’ consultant, Navigant Consulting, Inc. Data
presented is based on the original reported contract cost reductions for this contract, as presented in the first column of Table 8 on page 49
using the negotiation model. Positive amounts represent cost reductions, while negative amounts represent cost increases.
The issue of the appropriate discount rate to use for a present
value calculation is a contentious one. The higher the discount
rate used, the lower the present value of a given stream of future
payments. In making power-purchasing decisions, utilities
often use their weighted average cost of capital. However, in
determining the present value from the ratepayers’ perspective,
a percentage equivalent to the rate of return consumers would
receive for an investment of similar risk should be used. The
result represents the amount ratepayers would be required to
invest today to receive a future stream of payments equivalent
to the expected ratepayer savings. The department consultant
used two discount rates in its analysis, 5 percent and 9 percent.
The 5 percent rate was used because it represented the
department’s cost to borrow funds, while the 9 percent rate was
5566 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5577
an approximation of a private party’s borrowing cost. However,
the department consultant acknowledged that others could
argue that a higher discount rate should be used. Our consultant
believes that a 9 percent discount rate is consistent with the
rates that public utility commissions typically use to evaluate
such transactions on behalf of consumers.
Table 11 shows the distribution of the $1.5 billion estimate
in ratepayer savings over time. While ratepayers will bear
additional costs through 2005 as a result of the renegotiations,
they will realize significant savings after this time. However,
because most of the ratepayer savings in the renegotiated
contracts do not accrue immediately, the present value of the
savings is considerably smaller than the nominal contract cost
reductions that were reported.
TABLE 11
Yearly Ratepayer Savings From Contract Renegotiations
(in Millions, Nominal)
2001 $ 0
2002 -28
2003 -152
2004 -44
2005 -31
2006 81
2007 84
2008 162
2009 138
2010 396
2011 198
2012 254
2013 -10
2014 -26
2015 0
2016 80
2017 80
2018 80
2019 80
2020 80
2021 47
Total $1,469
Source: The Department of Water Resources’ consultant, Navigant Consulting, Inc. Positive
amounts represent ratepayer savings, while negative amounts represent ratepayer costs.
5566 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5577
For the entire portfolio, the department consultant’s analysis
indicates that total ratepayer savings from all renegotiated
contracts are currently estimated to be about $580 million on
a present value basis, as shown in Table 12. As we mentioned
previously, the estimates of contract cost reductions and
ratepayer savings are highly dependent on expected future
market conditions. The data presented in Table 12 reflects both
changes in market conditions since the department negotiated
the restructured contracts and the use of the department’s
revenue requirement model, which is able to consider the effects
on the entire total portfolio of all of the renegotiations.
The department had not intended to estimate the savings to
ratepayers that resulted from the contracts that were renegotiated
through December 31, 2002. According to the department,
the March 2003 estimate of savings to the consumer from the
renegotiated contracts as of December 31, 2002, using the
revenue requirement model, was made only at our request,
and the department would not otherwise have made this
calculation. In addition, the amounts are from its consultant’s
draft report and as of March 17, 2003, the amounts had not
gone through the department’s ordinary standards of review
for reports of this nature. However, this is the only estimate the
department provided to us of the savings to the consumer from
the renegotiated portfolio as of December 31, 2002. Further, the
department asserts that specific information from the revenue
requirement model, such as the percentage of power that was
eliminated through the renegotiations but will need to be
replaced and the cost reductions for each renegotiated contract, is
confidential and cannot be publicly disclosed.
As shown in Table 12, while the department consultant
estimates on a nominal basis that the total portfolio contract
cost reductions are about $4.8 billion, after considering
replacement power costs the department consultant estimates
that the customer savings are about $1.5 billion. Similarly, the
department consultant estimates that the net present value
of the contract cost reductions, at a 9 percent discount rate, is
about $2.3 billion and customer savings are about $580 million.
This analysis was performed by the department consultant using
the revenue requirement model in early 2003, and it therefore
was not available to negotiators during the renegotiations.
5588 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5599
TABLE 12
Estimated Ratepayer Savings From Renegotiations
(in Millions)
Nominal Net Present Value Net Present Value
Value at 5 Percent at 9 Percent
Total original contract cost $44,437 $36,938 $32,449
Total contract cost
after renegotiations 39,614 33,770 30,141
Reduction in contract costs
from renegotiations 4,823 3,168 2,308
Cost to replace power
that was eliminated
through renegotiations (3,354) (2,298) (1,728)
Cumulative customer savings
of renegotiated contracts 1,469 870 580
Source: The Department of Water Resources’ consultant, Navigant Consulting, Inc. The
amounts above show the effect on the total portfolio and are based on market assumptions in
the first quarter of 2003. The replacement power costs assume that the purchases are made
on the spot market. The $44.4 billion of original contract costs differs from the previously
mentioned $42.9 billion of original contract costs on page 23 due to the change in market
conditions between 2001 and 2003.
The department consultant’s analyses performed with the
negotiation model at the time its contracts were being restructured
generally included estimates of both contract cost reductions and
ratepayer savings, particularly with the larger contract renegotiations.
Further, it performed these estimates on both a nominal and
present value basis. Documentation provided by the department
indicates that the estimates were available to the negotiators to assist
them in evaluating proposals being offered by the suppliers. The
documentation also shows that the department and the governor’s
office had both estimates of ratepayer savings available when they
reported nominal contract cost reductions in press releases.
The department states that the decision to report the nominal
value of the contract cost reductions was consistent with the
previously reported $42.9 billion nominal cost estimate of
the department’s portfolio. It also states that it did not report
the ratepayer savings figures because of the limitations of
calculating that number. In making these decisions, however,
the department did not provide ratepayers with a relevant piece
of information related to the outcome of the renegotiations.
Disclosing ratepayer savings—on both a nominal and present
value basis—would have put the savings from individual
contracts that were renegotiated into context.
5588 California State Auditor Report 2002-009 California State Auditor Report 2002-009 5599
The deputy director in charge of the department’s power
activities provided the following additional comments about
using the estimated customer savings:
“The Department and its consultants have indicated
that they believe the forecasts of customer savings
using a single model output for a long term (in this
case, ten-year) projection of savings is a rough estimate
at best and cannot be relied on to accurately predict
actual customer savings in the future. Retail customer
savings projections require estimating the most volatile
part of the net short energy requirements—the portion
of remaining energy that is still required by electric
customers after accounting for the utilities’ existing
power supplies and the Department’s contracts.
Therefore, estimating both the amount and the price
of the replacement energy needed to determine retail
customer savings is subject to many variables that can
change over a multi-year period and are not easily
captured in a single energy volume and pricing model.
Examples of a few of these variables include: total future
electric demand, future gas prices, seasonal variations
from year to year on the amount of hydroelectric
energy (subject to variable regional rainfall levels),
market structure at the federal or state level, and the
amount of energy that direct access customers elect
to purchase from suppliers other than the utilities.
In addition, the Department’s consultants assumed
that all of the net short energy no longer met by the
Department’s renegotiated long-term contracts would
be met by spot market purchases, a very conservative
assumption. To the extent that the utilities enter into
long-term contracts to acquire such replacement energy
or already have replacement energy sources in their
portfolios rather than make spot market purchases,
the costs would differ and change customer savings.
The renegotiated contract savings, which we included
in press releases, are less susceptible to these variables
than customer savings. Promptly following each
renegotiation, the Department disclosed the entire text
of the contracts on its website, so that others could
calculate customer savings using their own assumptions
for these variables.
6600 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6611
In addition, the model used by the Department’s
consultant does not attempt to capture all the value
associated with the improvements made to the
renegotiated contracts. For example, it does not
ascribe differing values to differing kinds of energy
products, e.g., dispatchable vs. must-take energy,
even though such products have inherently different
economic values. Likewise, it does not attempt to value
the various non price-term contract modifications.
Although these changes will convey value to ratepayers
through greater reliability and other means, they are
not captured in the customer savings analysis given the
difficulty in quantifying the economic value. For all of
these reasons, the customer savings estimate should
be read only in the context of the assumptions and
limitations of the model and against the backdrop of
the overall improvements to the contract.”
It is difficult to reconcile the department’s qualification of its
own customer savings estimates as “rough estimates at best
and cannot be relied on to accurately predict actual customer
savings” with its own development and use of these estimates.
Department records confirm that its consultant used two
models, one simplified (the negotiation model) and one more
complex (the revenue requirement model), to derive estimates
of customer savings as part of the information provided
for consideration by the negotiating team as it evaluated
renegotiation opportunities. Our consultant offers the following
observations on the department’s qualification of these forecasts:
• The department consultant responsible for preparing those
forecasts specializes in such forecasts and prepares them for
the department and its other clients on a regular basis.
• Forecasts of this type are commonly prepared and used in
decisions on power contracts, recognizing that any forecast
cannot resolve inherent uncertainties in future market conditions.
• Customer savings estimates do require complex forecasts of
future market conditions. The department consultant utilizes
a commonly accepted forecasting model, PROSYM, to develop
the more detailed forecasts, one that the department consultant
has used consistently for analyses provided in support of the
department’s power program over the past two years.
6600 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6611
• These forecast methods were used by the department
consultant in the consultant’s report provided in support of
the revenue bonds that the department issued in October and
November 2002.
• These forecasts are consistent with the forecasts prepared by
the department consultant in establishing the department’s
revenue requirements, and its models and assumptions
have been reviewed by the CPUC and many others in the
development of those forecasts.
• The ratepayer savings figures are the department consultant’s
estimates based on market conditions at a given point in time,
as noted previously in this chapter.
• These forecasts do not capture the many nonprice provisions
obtained in the renegotiations, as is noted in Chapter 3 and
elsewhere in this audit report.
Our consultant also advises that despite the inevitable limitations
inherent in such forecasts, the department’s renegotiation
objectives recognized the importance of customer savings. The
department is to be commended for its efforts to estimate the
direct customer savings at the time it renegotiated the contracts.
As noted further in Chapter 6, we recommend that the
department monitor market conditions on a going-forward basis,
reflecting changes in market conditions as they become known,
to continue to make informed decisions on contract management
that can have material implications for savings to consumers.
Finally, our consultant states that it is important to remember
that, going forward, the contracts remain well above the
department consultant’s current (albeit uncertain) estimates
of future market prices. This in no way concludes that there
was a better price outcome available to the negotiating team
last year, nor does it say anything about the value of the other
concessions gained. Consequently, we make no finding that the
renegotiation efforts were flawed or were unsuccessful. Without
great leverage, the renegotiations could not hope to fully
reconcile the contracts to current market prices and terms, and
thus, as we discuss in Chapter 6, the department must continue
to look for (and make) opportunities to further improve those
contracts. As a part of that effort, the department needs to do
the analysis necessary to assess changing market conditions and
assess the merits of any future proposals or opportunities.
6622 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6633
MUCH OF THE DEPARTMENT’S PORTFOLIO REMAINS
AT ABOVE-MARKET PRICES
Contract prices after the renegotiations remain well above the
future prices projected by the department consultant, as shown
in Figures 6 and 7 on the following pages. Contracts for standard
nondispatchable energy products, which still make up more
than 90 percent of all energy purchases in the department’s
portfolio, remain priced substantially above expected market
prices. However, the negotiations have reduced the average
prices of such products by eliminating high-priced purchases, as
well as by reducing some contract prices.
Figure 6 compares the average price of around-the-clock (7x24)
nondispatchable energy before and after renegotiations with the
most recent projection of future spot market prices prepared by
the department consultant, reflecting market conditions in early
2003. It shows that for the period from 2002 to 2010, prices for
this product declined by an average of $3 per megawatt-hour as
a result of the negotiations. However these prices still average
about $15 per megawatt-hour above expected market prices.
Also as a result of the negotiations, obligatory purchases of
energy associated with this 7x24 product were reduced by about
10 percent during this period.
Due to changes in market expectations, forecasts of market
prices can be expected to change over time, affecting the relative
Contracts for standard cost of these nondispatchable energy purchases to market prices.
nondispatchable energy Further, because nondispatchable energy purchases provide a
products remain priced shelter against the volatility of spot market prices by locking in a
substantially above fixed price for future purchases, it can be expected that over time
expected market prices such purchases will command a premium over market prices,
although the negotiations although of varying magnitude depending on demand and
have reduced the average supply conditions. However, our consultant believes that the
price of such products. current differential between nondispatchable energy purchases
and expected market prices is greater than these factors would
suggest it should be.
6622 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6633
FIGURE 6
Average Price of the Department’s 7x24 Nondispatchable Energy
Before and After Renegotiations Compared to Projected Spot Market Prices
���������������������������������
�������������������������������������
����������������������������������
���
��
��
��
��
��
��
��
�
���� ���� ���� ���� ���� ���� ���� ���� ����
Sources: La Capra Associates’ analysis of data from the Department of Water Resources’ consultant, Navigant Consulting, Inc.
Projected spot market prices are all-hours average prices in the Northern California zone, as forecasted by Navigant Consulting, Inc.,
based on a March 2003 analysis.
Figure 7 presents the same information for peak-hour (6x16)
nondispatchable energy blocks and peak-hour market prices. As
shown in Figure 7, after 2005 prices for the nondispatchable peak
product after negotiations converge with projected peak-hour
market prices. However, while the negotiations reduced prices
by an average of $15 per megawatt-hour through 2010, these
prices remain about $16 per megawatt-hour above projected
market prices through 2005. The negotiations produced a
2 percent increase in the quantity of nondispatchable peak-hour
purchases. As in the case of the 7x24 nondispatchable purchases,
while forecasts of market prices will change over time and fixed-
price nondispatchable purchases provide value by sheltering
the department from volatile spot market prices, our consultant
believes that through 2005 these contract prices remain high
relative to market expectations.
6644 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6655
�����������������������
FIGURE 7
Average Price of the Department’s 6x16 Nondispatchable Energy
Before and After Renegotiations Compared to Projected Spot Market Prices
���������������������������������
�������������������������������������
���������������������������������
����
���
���
��
��
��
��
�
���� ���� ���� ���� ���� ���� ���� ���� ����
Sources: La Capra Associates’ analysis of data from the Department of Water Resources’ consultant, Navigant Consulting, Inc.
Projected spot market prices are the on-peak average prices in the Northern California zone, as forecasted by Navigant Consulting, Inc.,
based on a March 2003 analysis.
The figures show that while the average price of these products
under the renegotiated portfolio has fallen, power delivered
from the portfolio still remains at prices above current market
projections of the department consultant. As we noted
previously, much of the cost reductions were the result of
shortening contract lengths, but it appears that the State has had
little success in convincing suppliers to lower the prices they are
charging for power. It is clear that in the future, the department,
the investor-owned utilities, and the CPUC will need to
continue to manage cost risks associated with the portfolio in
accordance with their respective roles. Further renegotiations as
the opportunities arise may be one avenue to do so. We discuss
additional recommendations in Chapter 6 of this audit report. n
6644 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6655
�����������������������
Blank page inserted for reproduction purposes only.
6666 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6677
CHAPTER 3
The Renegotiated Contracts Improve
the Reliability and Flexibility of the
Department’s Energy Portfolio, but
Challenges Remain
CHAPTER SUMMARY
Although as Chapter 2 discussed, the readily quantifiable
economic benefits of the renegotiated contracts to
individual consumers are likely to be modest, our review
indicates that the renegotiations generally resulted in stronger
guarantees that the sellers will deliver the power promised under
the contracts and will build the new generation units promised
in the contracts. Thus, the renegotiated contracts better meet
the reliable energy goals of Assembly Bill 1 of the 2001–02 First
Extraordinary Session (AB 1X) and better ensure the availability
of electricity to satisfy consumer demand. These improvements
are accomplished through stronger terms and conditions,
such as termination rights for the State and penalty provisions
when sellers fail to deliver energy or construct new generation
units as promised under the contract. Although not readily
quantifiable, these changes are also likely to provide economic
benefits to ratepayers. In addition, changes in the type of energy
products purchased under the contracts increase the reliability
of the Department of Water Resources’ (department) long-term
contract portfolio. As noted in Chapter 1, changes in the types
of energy products purchased also serve to improve the fit of the
department’s supply portfolio relative to its net-short obligation
and have economic value, as discussed in Chapter 2.
Since our December 2001 audit, the power-purchase authority
given to the department under AB 1X has ceased. Further, through
a series of rulings and orders issued by the California Public Utilities
Commission (CPUC), the day-to-day management and operation
of the long-term energy contracts has been transferred to the
investor-owned utilities. Nonetheless, the department remains
legally and financially responsible under the contracts.
The renegotiated contracts all contain clauses known as
novation clauses, which call for transfer of the contract to the
investor-owned utilities if two key events occur. According to
the department’s legal counsel, sellers would only agree to the
6666 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6677
clause if it was made contingent upon the creditworthiness of
the investor-owned utilities and upon the CPUC’s determination
that the contracts are just and reasonable. Thus the timing of the
complete transfer of contract responsibility is uncertain. Moreover,
the original contracts that have not been renegotiated do not
have the novation language that now exists in the renegotiated
contracts, making it more diffi cult to transfer those contracts to the
investor-owned utilities. As a result, the department continues to
have signifi cant legal and technical responsibilities for the ongoing
management of the long-term contracts.
OUR DECEMBER 2001 AUDIT IDENTIFIED NUMEROUS
WEAKNESSES IN THE TERMS AND CONDITIONS OF
THE LONG-TERM POWER-PURCHASE CONTRACTS
In our December 2001 audit, we measured the department’s long-
term power-purchase contracts against the stated purpose of AB 1X
of ensuring a reliable source of energy at the lowest possible price.
In reviewing the long-term energy contracts (contracts), we found
that they lacked many of the terms and conditions we would
expect to see in contracts designed to provide reliable
energy to consumers. In contrast, we noted that the
Our December 2001 audit evaluated the prices paid for energy in the contracts were likely to
reliability and price stability of the contracts be well above market prices, which gave sellers an
using the following factors:
economic incentive to continue to deliver energy
• Reliability of performance—delivery. under the contract but did not adequately protect
Does this contract have terms that ensure
the State’s interests. Thus, we reported that the
that the seller will deliver the energy that it
agreed to provide under the contract? contracts might not always ensure that power would
be delivered when wanted except by conferring
• Reliability of performance—availability.
Does this contract have terms that ensure substantial benefi ts on sellers for delivery.
that facilities will be available to deliver the
power the seller agreed to provide under
In reaching our conclusions, we performed an
the contract?
in-depth analysis of fi ve contracts (Allegheny,
• Reliability of performance—building
Calpine, Coral, Sempra, and Sunrise), as well as
new generation. If the contract relies on
the construction of new generation units, an in-depth analysis of certain provisions of the
does the contract have terms that ensure
Williams contract. In addition, we performed a
that the units will be built?
higher-level review of other contracts, which were
• Price risk—uncertainty of price. Does reported on a contract “report card.” We identifi ed
the contract have terms that ensure
several key terms that we would expect to see in long-
price stability?
term energy contracts designed to provide reliable
electricity supplies, as outlined in the text box at left.
Using these criteria, we found that the majority of the contracts
we reviewed were lacking in several of these categories. In
reviewing the terms and conditions, we found that the contracts,
particularly the early ones, lacked provisions that would ensure
6688 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6699
reliable delivery of power. Moreover, we found that the types
of energy products the department purchased also affected the
reliability of the department’s portfolio.
Based on these fi ndings, we made several legal recommendations
for the original contracts. We recommended that the department
fi rst conduct an in-depth assessment of legal risks associated with
In our December 2001 the contracts. We also recommended that the department develop
audit we found that the an effective legal management strategy based on the results of
contracts were not easily that assessment, to identify the department’s leverage points and
assignable to investor- the trouble spots that the department needs to guard against in
owned utilities. the contracts. In addition, we recommended that the department
develop a contract renegotiation strategy that focused on
improving the reliability and overall performance of the portfolio.
Given the weaknesses we identifi ed in the original contracts,
in the December 2001 audit we also evaluated the contracts to
determine the department’s ability to renegotiate or
quit the contracts. Also, because the department’s
Our December 2001 audit also evaluated the power-purchasing authority under AB 1X was to
contracts on the following basis:
end on December 31, 2002, we evaluated whether
• Flexibility to renegotiate or quit the contracts would permit an easy transition from
the contract:
the department to the investor-owned utilities. We
§ Constraints on the department’s ability found that the long-term energy contracts were not
not to perform.
easily assignable to the investor-owned utilities,
§ The department’s ability to obtain relief and thus we identifi ed a need for the department
through governmental action.
to develop a strategy for its ongoing legal and
• The department’s ability to assign or technical responsibilities. We recommended
delegate the contract if the department that the department establish an ongoing legal
exits the program.
services function that specializes in power contract
management, negotiation, and litigation, and that
the department investigate all audit and other rights
available to it under its contracts to ensure that it can develop a
proper performance enforcement program.
THE TERMS AND CONDITIONS OF THE RENEGOTIATED
ENERGY CONTRACTS BETTER ENSURE RELIABLE SUPPLIES
OF ENERGY
As we discussed in detail in the Introduction, since the
December 2001 audit the department has assembled a team of
legal and technical experts to examine the contracts, set goals
for renegotiation, identify opportunities to enter renegotiations,
and renegotiate the contracts. The team has vigorously pursued
renegotiation of both the price and reliability terms of the
energy contracts, as seen in Table 13 on the following page.
6688 California State Auditor Report 2002-009 California State Auditor Report 2002-009 6699
TABLE 13
Summary of Contracts Renegotiated in 2002
2003 Capacity* Percent
Contract (In Megawatts) of Portfolio Product Changes†
Cabazon 43 0.3% None
Calpine 3,175 23.9 Fixed energy price to gas tolling on 495
megawatts for 2002 to 2009.
Capitol Power (terminated) – – N/A
High Desert 1,330 10.0 Approximately 60,000 gigawatt-hours of
nondispatchable energy replaced with up
to 800 megawatts of dispatchable capacity
through 2011.
Whitewater Hill 65 0.5 None
Calpeak 291 2.2 49 megawatts moved to NP15.
Soledad 13 0.1 N/A
GWF 340 2.6 None
Colton Power (formerly Alliance) 80 0.6 None
PG&E 66 0.5 None
Williams 1,875 14.1 Approximately 40,000 gigawatt-hours of
nondispatchable energy replaced with
dispatchable capacity that varies from 430 to
1,175 megawatts through 2010.
Clearwood 25 0.2 None
Santa Cruz 3 0.0 None
Wellhead Power 118 0.9 None
Sunrise 560 4.2 None
Total—Renegotiated Contracts 7,984 60.0%
Total—Renegotiated Portfolio 13,262
* July/August peak-hour capacity.
† Only addresses product changes, which includes effective replacements of product type but not straight additions, deletions, or
reductions of products.
N/A = Not applicable.
For this audit, we reviewed the terms and conditions of the
renegotiated contracts with 6 sellers (Calpine, GWF, High Desert,
Calpeak, Williams, and Sunrise), using the same criteria we
measured them against in the December 2001 audit. First,
we looked at whether the renegotiated provisions meet the
stated purpose of AB 1X to ensure a reliable source of energy
at the lowest possible price. We also reviewed the contracts for
improvements in the department’s ability to transfer them to
7700 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7711
the investor-owned utilities. In Appendix C we have updated
our contract report card to reflect the changes we found in the
renegotiated contracts we reviewed.
Although the readily quantifiable economic benefits that the
renegotiated contracts will have for individual consumers are
likely to be modest, our review indicates that the renegotiations
resulted in stronger guarantees that the sellers will deliver the
power promised under the contracts and will build the new
generation units promised in the contracts as seen on Table 14
on the following page. Thus, the renegotiated contracts better
meet the reliable energy goals of AB 1X and better ensure the
availability of electricity to satisfy consumer demand. Although
not readily quantifiable, these changes are likely to provide
some economic benefit to ratepayers. These improvements are
accomplished through stronger terms and conditions, such as
termination rights for the State and penalty provisions when
sellers fail to deliver energy or construct new generation units as
promised under the contract. In addition, changes in the type
of energy products purchased under the contracts increase the
reliability of the department’s long-term contract portfolio. As
noted in Chapter 1, changes in the types of energy products
purchased also serves to improve the fit of the department’s
supply portfolio relative to its net-short obligations. According
to our consultants, such changes have economic value that is
captured as part of the $900 million estimate of contract cost
reductions from combined product and quantity changes, as
presented in Figure 5 on page 53.
In reviewing the renegotiated contracts, we found that they
have resulted in major improvements in many of the areas we
identified as weak in our December 2001 audit. The changes
in the renegotiated contracts are the product of complex
negotiations between the sellers and the State. As a result, the
changes are not always uniform in every contract and the gains
are not identical. Nonetheless, we found that they collectively
contain many of the terms and conditions we would expect
to see in contracts entered into with the goal of providing
reliable energy to consumers, as shown in Table 14. Thus,
while we found that not all contracts gained improvements in
each area that we identified as weak, as a whole the new terms
and conditions of each renegotiated contract make significant
improvements in the reliability of the power promised under
the contracts. Moreover, as seen in Table 13, several renegotiated
contracts resulted in changes in the types of energy products the
State is purchasing, which also increases the reliability of the
overall portfolio.
7700 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7711
TABLE 14
Changes in Contract Terms by Category
Contracts With Number of
Total Terms Rated Contracts Rated Percent of
Total Contracts Negatively in Negatively That Problem
Contracts With December 2001 Had Improved Terms
Category and Issues Graded Reviewed Changes Audit Terms Addressed
RELIABILITY OF ELECTRICITY SUPPLY
A. Reliability of Performance—Delivery
Is seller’s failure to deliver an event of
default? (–1, 0, 1) 10 8 7 5 71%
Penalties for seller’s nonperformance
(–1, 0, 1) 10 9 7 6 86
Seller’s contractual incentives to perform
(–1, 0, 1) 10 4 3 1 33
Seller’s price incentives to perform
(–1, 0, 1) 10 0 0 N/A N/A
Department’s ability to manage risk of
nonperformance (0, 1) 10 10 0 N/A N/A
Seller’s outs (–1, 0, 1) 10 7 8 6 75
B. Reliability of Performance—Availability
Is seller’s failure to perform an event of
default? (–1, 0, 1) 10 7 7 4 57
Penalties for seller’s nonperformance
(–1, 0, 1) 10 10 3 3 100
Seller’s contractual incentives to perform
(–1, 0, 1) 10 6 2 1 50
Seller’s price incentives to perform
(–1, 0, 1) 10 1 0 N/A N/A
Department’s ability to manage risk of
nonperformance (0, 1) 10 10 0 N/A N/A
Seller’s outs (–1, 0, 1) 10 5 6 4 67
C. Reliability of Performance—Building
New Generation
Is seller’s failure to perform an event of
default? (–1, 0, 1) 10 1 4 0 0
Penalties for seller’s nonperformance
(–1, 0, 1) 10 6 3 3 100
Seller’s contractual incentives to perform
(–1, 0, 1) 10 3 2 1 50
Seller’s price incentives to perform
(–1, 0, 1) 10 3 1 1 100
7722 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7733
Contracts With Number of
Total Terms Rated Contracts Rated Percent of
Total Contracts Negatively in Negatively That Problem
Contracts With December 2001 Had Improved Terms
Category and Issues Graded Reviewed Changes Audit Terms Addressed
Department’s ability to manage risk of
nonperformance (0, 1) 10 5 0 N/A N/A
Seller’s outs (–1, 0, 1) 10 0 4 0 0%
D. Price Risk—Uncertainty of Price
Seller’s pass-throughs (–1, 0, 1) 10 8 6 6 100
Department credits (0, 1) 10 7 0 N/A N/A
Allocation of environmental risk (–1, 0) 10 2 3 2 67
E. Price Risk—Tolling Agreement
Department’s exposure to fuel price risk
(–1, 0, 1) 10 6 0 N/A N/A
Department’s exposure to operating
inefficiency risk (–1, 0, 1) 10 5 0 N/A N/A
FLEXIBILITY TO RENEGOTIATE OR QUIT
A. Constraints on Department’s Ability
Not to Perform
Outs for department (–1, 0, 1) 10 9 6 5 83
Dispatchable versus take or pay (1, –1) 10 9 4 3 75
Limits of state’s liability (–1, 0, 1) 10 0 4 0 0
B. Department’s Ability to Obtain Relief
Through Governmental Action
Recoup expenditures through taxes (0,1) 10 1 0 N/A N/A
Obtain relief from FERC (0, 1) 10 3 0 N/A N/A
ABILITY TO ASSIGN/DELEGATE IF DEPARTMENT EXITS THE PROGRAM
Ability to assign/delegate to government
entities (–1, 0, 1) 10 0 0 N/A N/A
Ability to assign/delegate to
nongovernment entities (–1, 0, 1) 10 10 9 9 100
Source: Department of Water Resources’ data reviewed by the Bureau of State Audits.
Note: In many cases, changes in contract clauses affected multiple categories. In these cases, we evaluated the effect of
the change on each category. Also, this report card does not include the following renegotiated contracts because they are
insignificant in value to the overall portfolio: Cabazon, Clearwood, PG&E, Santa Cruz, Soledad, Wellhead Power, and Whitewater.
We reviewed a total of 16 transactions, but treated our review as a review of 10 contracts because the department treated them as
such. The 10 contracts are listed on page 148.
N/A = Not applicable.
7722 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7733
The renegotiated contracts represent more than one-half of the
value of the State’s long-term contract portfolio. As a result, the
renegotiated contracts have improved the reliability of roughly
half of the energy portfolio. Further, all of these improvements,
although difficult to quantify, are likely to provide some
economic benefit to ratepayers.
The Renegotiated Contracts Make the Delivery of Power
More Reliable
In our December 2001 audit, we examined the contracts for
provisions that would ensure that sellers deliver electricity as
called for by the contracts. Our consultants advised us that
Provisions ensuring reliable provisions ensuring reliable delivery were particularly important
delivery were particularly in an environment in which the State suspected generators of
important in an engaging in activities such as withholding power to drive up
environment in which the spot market prices. We found that the terms and conditions of
State suspected generators the majority of the original long-term contracts may not assure
of engaging in activities the reliable delivery of promised power. For example, we found
such as withholding that under most of the original contracts we reviewed, failure to
power to drive up spot deliver energy is rarely defined as an event of default that would
market prices. give the department the right to terminate the contract, and
the contracts also do not assess penalties on sellers for failing to
deliver promised power. Thus, under these original contracts the
department cannot terminate a contract or assess penalties, even
if a seller repeatedly or deliberately fails to deliver power, and
even at times when the State is in dire need of it. Instead, the
department is limited to recovering the difference between the
contract price and the price the department has to pay to replace
the energy the seller failed to deliver, a remedy commonly
known as cover damages. We found that cover damages are not
adequate to ensure delivery of power, because they assume that
an adequate supply of power will be available from which the
buyer can purchase replacement power. As demonstrated by the
numerous warnings of potential blackouts in 2000 and 2001,
however, that may not be a valid assumption in California’s
energy market.
All of the renegotiated contracts have terms that better assure
that power will be delivered as promised, as seen in the box on
the following page. For example, the remedies available to the
State under the renegotiated contracts in the event of default
impose greater penalties on the seller and make it much more
likely that the seller will be motivated to perform.
7744 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7755
The renegotiated Calpine, High Desert, and
Williams Product D contracts still provide
Reliability of Performance—Delivery
cover damages for failure to deliver. However,
Contracts in addition to that remedy, those contracts
Criteria Changed
now call for payment adjustments for failure
Is the seller’s failure to deliver to deliver. Moreover, those contracts, as well as
an event of default? 8
fi ve others, now make failure to deliver power
Penalties for seller’s under the contract an event of default under
nonperformance? 9
certain circumstances. Once an event of default
Seller’s contractual incentives
occurs, the State may be entitled to terminate the
to perform? 4
contract and, under some circumstances, to collect
Seller’s price incentives
termination damages.
to perform? 0
Department’s ability to manage
risk of nonperformance 10 For example, the renegotiated GWF contract
makes it an event of default for GWF to willfully
Seller’s outs 7
fail to make power available as called for by the
contract and to instead deliver the energy to a
third party. If that event of default occurs, the State
may terminate the contract and receive termination damages
equal to the difference between what the department would
have paid for the power under the contract and the cost of the
replacement power.
Similarly, in the renegotiated Williams Product D contract, an
event of default occurs under two circumstances: if Williams
fails to deliver power during a stage emergency called by the
California Independent System Operator (ISO) or if Williams has
three unexcused failures to deliver. The threat of termination for
failure to deliver under these circumstances gives the sellers a
powerful incentive to ensure that power is delivered to the State
when necessary. The Williams Product D contract is noteworthy
in that it ties this threat to failures to deliver electricity when the
State needs it most—that is, during the stage emergencies called
by the ISO, when the State’s electricity supply is tight and rolling
blackouts may occur.
Ten of the renegotiated contracts also have other terms and
conditions that encourage sellers to perform, such as penalties
for failure to deliver. For example, several of the original
contracts call for the payment of capacity payments to sellers.
Long-term energy contracts often include capacity payments,
which pay generators a fee for keeping specifi ed amounts of
energy capacity available to the buyer. When the buyer actually
schedules energy for delivery, the buyer then pays an additional
fee per megawatt-hour for the energy that is actually delivered.
The capacity payment is thus simply a payment in exchange
7744 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7755
for keeping power available at certain levels. In contracts of this
type, language clearly delineating the seller’s responsibilities
to maintain the availability of the contract supplies can help
ensure reliable supplies of energy.
Several renegotiated contracts contain major revisions of
contract language relating to capacity and, as a result, have
strengthened the reliability of those contracts. For example,
two of the renegotiated Calpine contracts (Calpine 3 and
Calpine 4) require a reduction in capacity payments for failure
to deliver electricity as called for by the contract. The two other
Calpine contracts (Calpine 1 and Calpine 2) require a reduction
in capacity payments if the rate at which Calpine delivers
electricity is below 95 percent of the capacity of the generating
units the contract designates to produce electricity.
Four of the renegotiated contracts call for the seller to pay
the State liquidated damages for failure to deliver under
certain circumstances. Liquidated damages are essentially a
Penalties for failure predetermined or agreed-upon estimate of the loss or damage
to deliver power that the buyer will suffer if the seller fails to deliver. For example,
during ISO stage the renegotiated High Desert contract imposes a $7.5 million
emergencies discourage penalty for intentional withholding of power. Similarly, the
market manipulation. GWF and Sunrise contracts require the sellers to pay the State
$1.5 million in liquidated damages for willful failure to deliver
during an ISO stage alert. Penalties for failure to deliver power
during ISO stage emergencies provide additional incentives for
sellers to deliver power when it is most needed and discourage
the market manipulation that the State suspects generators
engaged in during the height of the energy crisis. The High
Desert contract, for example, imposes a penalty by making the
seller responsible for the payment of ISO imbalance charges that
result when energy is not delivered as required by the contract.
Four of the renegotiated contracts provide contractual incentives
to sellers that improve the reliability of the delivery of power. For
example, the Calpine 3 and Calpine 4 contracts promise capacity
payment bonuses if the capacity of designated new generation
units exceeds the amounts designated in the contracts.
All of the renegotiated contracts contain provisions that
improve the ability of the department to manage the risk that
the seller will not deliver power. For example, the Calpine 3
and Calpine 4 contracts restrict improper use of the imbalance
energy market to effect delivery of power, and other contracts
provide the department with access to real-time data, enabling
7766 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7777
the department to better anticipate shortfalls in supplies. The
threat of penalties and termination also provides the department
with better tools to ensure seller performance.
Seven renegotiated contracts include provisions that impose
greater limits on excuses for seller nonperformance. The
renegotiated Calpeak, Calpine, and Williams Product D contracts
contain revisions to the force majeure clauses. These clauses
generally excuse generators from performing under contracts if
certain defined events beyond the control of the generator occur.
Under those circumstances, failure to perform is not an event of
default or grounds for termination, nor is the generator liable
for any damages. In our December 2001 audit, we found that
most force majeure clauses were broadly worded, providing the
generator with a wide range of excuses for failure to deliver. In
contrast, the renegotiated Calpine contract, for example, narrows
the force majeure clause by excluding from that definition events
relating to defined economic factors or Calpine’s failure to operate
generating units within prudent industry standards. Through
narrowed force majeure clauses, giving sellers fewer excuses for
failing to deliver electricity, the sellers have greater incentives to
deliver power as called for by the contract.
By renegotiating the contracts to contain these enhanced
reliability provisions, the department has increased its ability to
manage the risk of nonperformance in each renegotiated contract.
The Renegotiated Contracts Better Ensure That Power Is
Available When Needed
In our December 2001 audit, we also examined the original
contracts for provisions that would ensure that electricity is
actually available for delivery as called for by the contract.
Because electricity cannot be stored, provisions ensuring that
energy is available when needed, especially during peak demand
Provisions ensuring that periods, are essential to ensuring reliable sources of energy.
energy is available when We found that the original contracts generally lack provisions
needed are essential that ensure that the energy the department is entitled to under
to ensuring reliable the contract is actually available when the State needs it. For
energy supplies. example, the original contracts generally do not require that the
generating units designated to supply power under the contract
be operated and maintained within prudent industry standards.
Similarly, few of the original contracts provide the department
with the right to inspect and monitor generators to ensure that
units are being properly maintained and available to deliver
energy. We found that the right to inspect any unit having an
7766 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7777
unscheduled outage, in order to confi rm that the outage was
due to a genuine operating failure, would be valuable if the State
suspected that generators were seeking to drive up prices by
inappropriately withholding generation.
All of the renegotiated contracts contain provisions
that should help ensure that the energy the
Reliability of Performance—Availability
department is entitled to under the contract is
Contracts actually available when the State needs it, as shown
Term Changed
in the box at left.
Is seller’s failure to perform
an event of default? 7 As we discussed earlier, several contracts now
Penalties for seller’s reduce the capacity payments that the State would
nonperformance 10
otherwise owe under a contract if the seller fails
Seller’s contractual incentives to maintain the availability of power at the levels
to perform 6
set in the contract. Seven of the renegotiated
Seller’s price incentives
contracts have provisions that permit the State
to perform 1
to terminate the contract if the sellers fail to keep
Department’s ability to manage
power available at the capacity level specifi ed
risk of nonperformance 10
in the contract under certain circumstances. For
Seller’s outs 5
example, the Calpine 1 and Calpine 2 contracts
permit the State to terminate the contract if for
two consecutive months Calpine delivers electricity
to the State at a rate that is below 95 percent of the capacity
levels required in the contract. The threat of termination and
loss of future payments under the contract gives Calpine strong
incentives to perform and thus strengthens the reliability of the
energy supply under the contract.
The Williams Product D contract establishes penalties if
Williams dispatches the energy capacity the State contracted for
to a third party. More specifi cally, if Williams dispatches power
to any other party or sells or commits the contract’s energy
capacity to another party, the State may terminate the contract
and Williams must pay the State liquidated damages amounting
to fi ve times what Williams would have been paid under the
contract if it had delivered the power to the State.
Three of the renegotiated contracts also have additional
incentives for sellers to maintain the availability of power.
For example, the Calpine 3 and Calpine 4 contracts and the
Williams Product D contract provide bonuses if the actual
availability of the designated generating units to produce power
exceeds the minimum number of megawatts the unit is required
to make available under the contract.
7788 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7799
Changes in Energy Products Enhance the Reliability and
Flexibility of the State’s Energy Portfolio
The types of energy products that compose the department’s
energy portfolio also affect the reliability of the supply of
power. Energy products often define how energy is delivered.
For example, during our December 2001 audit, we found that
the department’s energy contracts often contain two types of
energy products: unit contingent products, which excuse the
seller for failing to deliver power from the specified unit due to
force majeure events, and firm energy with liquidated damages
(firm LD contracts), which excuse the seller for failing to deliver
power in the case of force majeure events. A contract for unit
contingent energy products may be less reliable than a contract
for firm LD energy products because a unit contingent contract
excuses the seller from delivery from the designated unit for
various reasons, with no damages owed to the purchaser, while
firm LD energy contracts require the seller to either deliver
power from some source or pay cover damages.
Changes in energy products have improved the reliability of the
supply of power. For example, the original Calpine 1 contract calls
for unit contingent power, which makes Calpine’s obligation to
deliver power contingent on the ability of a specified generation
unit to produce the power. The renegotiated contract converts
it to a firm LD contract, which means Calpine must deliver the
called-for energy or pay the State cover damages.
The Renegotiated Contracts Calling for New Generation
Better Assure That the Generation Units Will Be Built
In our December 2001 audit, we reported that contracts calling
for the construction of new generation facilities have numerous
weaknesses in provisions relating to the new generation. Several
of the original contracts we reviewed in that audit rely on the
generator to build new generation units to provide the energy
the generator agreed to provide to the State. However, our
review of the original contracts revealed they lack provisions to
ensure that the new generating units they call for will actually
be constructed. This is particularly true of the early original
contracts. For example, the original contracts lack many
provisions that ensure performance, even though the State
pays a premium for the construction of the new generation
units in addition to the fee per megawatt-hour it will pay when
the power is actually delivered. We found that the original
contracts generally lack terms that (1) impose penalties on
the generator for failure to complete a unit as described in the
7788 California State Auditor Report 2002-009 California State Auditor Report 2002-009 7799
contract, (2) make failure to build the generation unit an event of
default, (3) mandate construction unless the seller can demonstrate
that construction was impossible, or (4) establish construction
milestones that the generator must meet, along with bonuses for
early completion or penalties for late completion. The absence of
these provisions makes it more diffi cult for the State
to ensure that new generating units are built and the
power is actually made available and delivered.
Changes in Reliability of Performance—
Building New Generation
The department has renegotiated several contracts
Contracts that call for the construction of new generation
Term Changed
units, representing a total of 5,400 megawatts
Is seller’s failure to perform that have and will become available to the State
an event of default? 1
over the next three years. All of these renegotiated
Penalties for seller’s contracts contain revised terms and have added
nonperformance 6
new terms that give the State greater assurances
Seller’s contractual incentives
that the sellers will actually build the new
to perform 3
generation units the contract calls for and that
Seller’s price incentives
the State needs to increase its overall generating
to perform 3
capacity. The box at left summarizes these changes.
Department’s ability to manage
risk of nonperformance 5
Moreover, under some renegotiated contracts, if a
Seller’s outs 0
seller fails to build the new generation units within
timelines specifi ed in the contract, the seller must
pay monetary penalties and in some circumstances
run the risk that the State will exercise its right to terminate the
contract for nonperformance. As a result, the renegotiated terms
not only increase the reliability of the department’s energy
portfolio but also better ensures that new generation units will
be brought on-line to meet the State’s future energy needs.
The department has exercised its right to terminate a contract for
nonperformance, canceling the renegotiated contract with Capitol
Power because the seller failed to bring agreed-upon generation
units on-line by July 15, 2002, as called for by the contract.
Three of the renegotiated contracts make payment of capacity
payments contingent on the generation units achieving
commercial operation or call for reductions in capacity
payments if the deadline to achieve commercial operation
is missed. Three of the renegotiated contracts also have new
contractual incentives for the sellers to perform. For example,
the Calpine 2 contract permits the State to take ownership of a
project if Calpine fails to meet construction and development
milestones. Although the State would essentially be required to
purchase the project from Calpine at cost to exercise that right,
8800 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8811
doing so in any of the years 2003 through 2010 would allow
the State to ensure that 495 megawatts per year are actually
added to the department’s portfolio. Moreover, the threat of
a state takeover and the loss of profits from the project give
Calpine a strong incentive to perform. In addition, if Calpine
does not achieve commercial operation of certain units by
December 31, 2003, the number of megawatts under the
contract is reduced. In other words, if Calpine does not have the
generators up and running by December 31, 2003, it loses its
contractual right to require the State to pay for those megawatts
in future years.
Six renegotiated contracts have penalties for failing to bring
new generation units on-line as promised. For example, while
Six renegotiated the original High Desert contract contains relatively few terms
contracts have penalties assuring that construction will occur, the new contract has
for failing to bring new numerous incentives for High Desert to perform. The contract
generation units on-line now makes it an event of default if High Desert fails to achieve
as promised. commercial operation by October 2004. Moreover, if the State
terminates the contract as a result of that default, High Desert
must make a $50 million termination payment to the State. The
High Desert contract will cost $2.4 billion, and thus a $50 million
penalty is quite substantial when coupled with the future profits
High Desert would lose upon termination of the contract.
Like the High Desert contract, the renegotiated GWF contract
also improves terms relating to new construction, although the
provisions are not quite as strong. The GWF contract provides
penalties for each day that a project designated under the
contract misses its construction deadline, and it permits the
State to terminate the contract if it has not met a July 1, 2003,
completion date. However, if the State exercises its right to
terminate, it is not entitled to termination damages, although
GWF still faces the prospect of losing future revenue under the
contract, thus providing GWF an incentive to perform.
Some of the contracts also improve the ability of the department
to manage the risk of the seller’s not performing. For example,
the Calpine 3 and Calpine 4 contracts have added language
requiring Calpine to provide periodic written reports to the State
regarding its progress toward achieving commercial operation
of the new generation units and permits the State to inspect
the units. The High Desert and GWF contracts contain similar
reporting requirements and inspection rights for the State.
Reports and inspection rights put the State in a position to
intervene and require the seller to correct problems before they
become critical, thus making the contract more reliable.
8800 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8811
The Renegotiated Contracts Better Manage Price Risks
In reviewing the sample of the original contracts, we found that
several of them leave the department vulnerable to price risks.
Generally, power-purchase agreements provide that all costs up
to the point of delivery are borne by the seller, and all costs after
the point of delivery are borne by the buyer. But the original
long-term contracts often permit sellers to shift costs to the State
based on various governmental actions.
For example, the original contracts commonly require the
department to pay for any new taxes that California might
levy that affect the generation or delivery of power. Others
require the department to reimburse the seller for any new taxes
imposed by any entity, including the federal government, as
well as for charges imposed by any federal agency, including the
Federal Energy Regulatory Commission (FERC). Some contracts
go so far as to increase the contract price for any increase in the
seller’s costs that results from any governmental action. Other
contracts permit sellers to pass on cost increases arising from
compliance with environmental regulations, such as the cost
of air emissions credits. We found that these provisions create
signifi cant contract management problems for the department
and risk exposing the department to future price
volatility as sellers seek to pass increasing costs on
to the department.
Changes in Price Risk—
Uncertainty of Price
Eight of the renegotiated contracts contain terms
Contracts that modify the price risks we identifi ed in our
Term Changed
December 2001 audit, and several make other
Seller’s pass-throughs 8 changes that make the price more certain, as
Department credits 7 summarized in the box at left.
Allocation of environmental risk 2
Eight of the renegotiated contracts modify the
language permitting the seller to pass its costs
through to the State. For example, the Calpine
contracts have narrowed the circumstances under which Calpine
may pass its costs to the State, and they entitle the State to
receive the benefi t of certain reductions in Calpine’s costs as
a result of government action. In other words, if Calpine’s
costs are reduced as a result of a reduction in taxes enacted
by the Legislature, the State is entitled to the benefi t of those
reductions, provided they relate to the Calpine transaction.
The original GWF contract permits pass-throughs to the State
for increased costs imposed by any local, regional, state, or
federal agency, but it now limits the pass-through of costs to
8822 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8833
increases resulting from action by the federal government
that is directed at electricity generation, sale, purchase, or
transmission. Finally, the overly broad language in the Williams
contract that we identified as particularly risky in Appendix B
of our December 2001 audit is now narrowed to permit
Williams to pass through only costs resulting from taxes or
other impositions enacted by the California Legislature that
are directed at assets or activities relating to generation, sale,
ownership, or transmission of electricity. The Williams Product
D contract still provides some protection for Williams from
government action by now permitting Williams to terminate
the agreement if the State refuses to adjust contractual payments
should Williams experience adverse financial circumstances
created by governmental action.
The renegotiated Williams Product D contract also provides better
price risk protection for the State by permitting the State to, in
effect, step into Williams’ rights to electricity under a long-term
energy contract that Williams has had with AES2 since May 1998
(AES agreement). The AES agreement is a capacity sale and tolling
agreement under which AES agrees to provide 3,956 megawatts
of dependable capacity to Williams over a 15-year period. While
the original Williams contracts seek to pass costs relating to
environmental regulation, such as air emissions penalties, along
to the State, the AES agreement, which the State now gets the
benefit of to the same extent that Williams does, requires AES to
bear the costs for complying with applicable environmental laws.
The original Williams contract does not tie the power it is
supplying to the State under its agreement with AES to its
contract with the State. Thus, under the original contract, the
State is not able to take advantage of numerous reliable energy
guarantees that Williams negotiated in the AES agreement,
even though Williams is likely providing at least some of the
energy to the State from supplies it is entitled to under the AES
agreement. Interestingly, the Williams–AES power agreement
contains many of the reliability guarantees that we expected to
find when we reviewed the original contracts.
The Renegotiated Contracts Better Protect the State From
Fuel Price Risks
In our December 2001 audit, we found that the terms of the
tolling agreements associated with the contracts we reviewed
are generally favorable to the State. As we discussed in Chapter 1,
2AES refers to AES Alamitos, L.L.C., AES Huntington Beach L.L.C.
8822 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8833
tolling agreements permit the buyers to take
advantage of decreases in natural gas prices.
Change in Price Risk—
Tolling Agreements Nonetheless, the renegotiation team sought, and in
several cases achieved, improvements in the tolling
Contracts agreements, as shown in the box at left.
Terms Changed
Department’s exposure to For example, the GWF contract now requires GWF
fuel price risk 6
to use commercially reasonable efforts to secure
Department’s exposure to
the best costs and terms for gas management
operating ineffi ciency risk 5
services and requires GWF to obtain at least two
competitive bids.
THE RENEGOTIATED CONTRACTS ARE MORE FLEXIBLE
AND EASIER TO TRANSFER TO INVESTOR-OWNED
UTILITIES, BUT CHALLENGES REMAIN
Since our December 2001 audit, the department’s power-
purchase authority under AB 1X has ceased. Further,
Assembly Bill 57, which became effective in September 2002,
laid the groundwork for transfer of energy purchasing back
to the investor-owned utilities. In response to that legislation
the CPUC, through a series of rulings and orders, required the
day-to-day management and operation of the long-term energy
contracts to be transferred back to the investor-owned utilities.
Nonetheless, the department remains legally and fi nancially
responsible under the contracts.
The renegotiated contracts call for the transfer of the contracts
to the investor-owned utilities when they are deemed
The renegotiated contracts creditworthy and upon the CPUC’s determination that the
call for the transfer to the contracts are just and reasonable, thus making the timing of the
investor-owned utilities transfer uncertain. Moreover, the original contracts that have
when they are deemed not been renegotiated do not have the assignment language
creditworthy—making that now exists in the renegotiated contracts, making it more
the timing of the diffi cult to transfer those contracts to the investor-owned
transfer uncertain. utilities. According to the department, seven original contracts
are candidates for renegotiation while others are not, primarily
because they have expired or will expire in the near future. As
a result, the department continues to have signifi cant legal and
technical responsibilities for the ongoing management of the
long-term contracts, as we discuss in detail in Chapter 6.
8844 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8855
The Renegotiated Contracts Provide the Department with
Greater Flexibility to Quit the Contract
As we discussed earlier, in view of the weaknesses we identified
in the terms and conditions of the original contracts with respect
to the reliability of power delivery, we also reviewed them for
opportunities for the department to quit or renegotiate the
contracts. In our December 2001 audit, we also noted that the
original contracts we reviewed place various restrictions on the
department’s ability to petition the FERC to void its power-purchase
contracts on the basis that the rates are not just and reasonable.
While we have reviewed the renegotiated contracts for
flexibility, this report does not evaluate whether the renegotiated
The new terms should contracts provide further opportunities to renegotiate the
provide the State contracts. We note, however, that in our December 2001 audit,
with better ability to we found that the limitations on the department’s ability to
aggressively administer declare events of default weaken its ability to aggressively
the contracts. administer the contracts, since contract management is often
dependent on the rights that it has against the seller. The new
terms should provide the State with better ability to aggressively
administer the renegotiated contracts and ensure seller
performance because the department’s ability to declare events
of default and to terminate contracts has improved significantly.
Further, the settlement agreements place some constraints on what
the State can do with regard to claims arising from the original
versions of the contracts. In the settlements, the State agrees to
release the majority of its pending claims arising from the original
contracts, as well as to release those claims arising from issues
relating to the validity of the contracts and whether they are just
and reasonable and to cease pending investigations. Although the
State gave up these rights, it appears that the benefits achieved in
the renegotiated contracts are worth the release of those claims.
In our December 2001 audit, we found that the original
contracts give the State few excuses for failing to perform its
obligations under the contract. In contrast, we found that
the contracts give the sellers numerous excuses for failing to
deliver, even when that failure is repeated and intentional, and
that the contracts also include excuses for failure to maintain
the availability of power and to construct new generation
units as called for by the contracts. Ten of the renegotiated
contracts lessen the constraints on the department’s ability not
to perform by providing the State with termination rights for
certain failures to deliver or failures to construct generation
units called for in the contracts. As we discussed earlier, several
8844 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8855
of the renegotiated contracts permit the State to declare an
event of default for repeated or intentional failure to deliver,
failure to meet availability requirements, or failure to bring new
generation units on-line within the timelines established by the
contracts. Thus, the renegotiated contracts now provide the State
with more opportunities to walk away from unreliable generators.
Product Changes Have Enhanced the Flexibility of
the Contracts
Changes in the product portfolio, as seen in Table 14 on
pages 72 and 73, have also increased the State’s flexibility and
provided the department with new tools to manage the risks of
nonperformance by the seller. The shift from nondispatchable
energy products to dispatchable energy products as reflected
in Table 2 on page 25, permits the department to schedule and
pay for power when needed, rather than paying for contracted
energy that it may not need during some periods.
The Williams renegotiation In addition to changing products, the department has
has resulted in a new successfully added products. For example, renegotiating the
fully dispatchable Williams contract has resulted in Williams Product D, a new,
product giving the State fully dispatchable product that includes full day-ahead, hour-
greater flexibility to ahead, and real-time energy scheduling rights for the State. The
schedule power. Williams renegotiation has given the State greater flexibility to
schedule power when it actually needs it, even an hour ahead or
on a real-time basis.
Renegotiation of the High Desert contract also resulted in a
product change. Under the original contract, the State purchases
unit contingent energy, meaning that High Desert is obligated
to deliver only if a designated unit is available. When the unit
is available, however, the State is required to accept delivery of
power, whether it needs it or not. The renegotiated High Desert
contract calls for dispatchable power, meaning that the energy
product in the High Desert contract has been changed from
one that the State was required to pay for whether it needed it
or not to one that gives the State flexibility to order and pay
as consumer demand requires. As shown in Table 2 on page 25,
through renegotiations about 800 or more megawatts of
dispatchable capacity has been added each year between 2003
through 2010. This not only results in costs savings to the State
but also provides the State with a more manageable portfolio.
8866 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8877
The Renegotiated Contracts Make Few Changes in
the Department’s Ability to Obtain Relief Through
Government Action
In the December 2001 audit, we also looked at the department’s
ability to obtain relief from the contracts by taking various
actions, such as renegotiation, reassignment of contract
obligations, or contract termination. In that audit, we noted that
the long-term contracts generally contain a clause that purports
to limit the department’s right to seek relief from FERC.
The renegotiated contracts have language stating that the contracts
are just and reasonable under the Federal Powers Act and state
law. Under the settlement agreements, the State agrees not only to
dismiss its FERC claim against the seller but also to dismiss other
claims and stop certain investigations of the seller by, for example,
the California attorney general. Thus, in most of the renegotiated
contracts, the State generally waives its rights to obtain further
relief from the original contracts through governmental action.
Finally, the State’s willingness to enter into these settlement
agreements was likely a factor in getting generators to the table and
in the ultimate renegotiation of the contracts.
The Renegotiated Contracts Call for Transfer to the Investor-
Owned Utilities, but the Department Faces Numerous
Challenges in the Process
In the December 2001 audit, we found that while the
department often has the authority to assign its rights under
the contract to another government entity, assignment to a
nongovernmental entity generally requires the consent of the
seller. We identified this as a challenge because AB 1X ended
the state’s power-purchasing authority on December 31, 2002,
with the goal of transferring that responsibility, as well as the
operational and legal management of the long-term contracts,
back to the investor-owned utilities. Obtaining the sellers’
consent to assign the contracts could involve protracted
negotiations, and not all sellers may agree to assignment. All
of the renegotiated contracts have addressed this concern by
adding a novation clause, which essentially transfers the rights,
duties, and responsibilities of the contracts to the investor-
owned utilities upon the occurrence of certain events.
The novation clause provides that any time after January 1, 2003,
the seller, at the request of the State, must enter into a new
agreement with one or more of the investor-owned utilities
and that execution of the new agreement is a novation that
8866 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8877
relieves the State of any liability or obligations under the
renegotiated contract. Under the novation clause there are
two hurdles that must be passed before the seller is obligated
to enter into the new agreement. First, the clause is triggered
only if the investor-owned utility to which the contract will be
assigned is creditworthy. Second, the CPUC must have issued
an order finding that the new agreement is just and reasonable
under Section 451 of the Public Utilities Code. According to
the department’s legal counsel, sellers would only agree to the
novation clause if it was made contingent on occurrence of
these two key events. Pacific Gas & Electric (PG&E), one of the
three largest investor-owned utilities, filed for bankruptcy in
April 2001, and those proceedings are likely to continue for
months to come. As a result, it is unlikely that PG&E will meet
the creditworthiness requirement anytime soon. Southern
California Edison (SCE) and San Diego Gas & Electric (SDG&E)
experienced similar financial challenges from the energy crisis.
According to the department, SDG&E is currently creditworthy,
and SCE is approaching creditworthy status. Thus, it appears that
the department will continue to have legal and management
responsibility for all of the contracts for several years.
The department was not able to assign its rights and obligations
to the investor-owned utilities under any of the long-term
energy contracts prior to January 1, 2003, nor do current
It appears the depart- conditions permit the department to assign any contracts
ment will have legal now, including the renegotiated contracts. Thus, to facilitate
and management the transition of energy purchasing back to the investor-
responsibility for all of the owned utilities, the CPUC has made several orders regarding
contracts for several years. the responsibilities of the investor-owned utilities to manage
the contracts after January 1, 2003. In September 2002, the
CPUC issued an order allocating portions of the contracts to
the investor-owned utilities. On December 19, 2002, the CPUC
issued operating orders that set forth the responsibilities of
the investor-owned utilities to perform functions under the
allocated contracts on behalf of the department in accordance
with the contracts.
As we explain in further detail in Chapter 6, the operating orders
require the investor-owned utilities to act as the department’s
agent in managing the operational duties called for by the
contracts. These orders state that the department remains legally
and financially responsible under each of the contracts and will
cooperate fully with the investor-owned utilities. The CPUC
8888 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8899
has regulatory authority only over the investor-owned utilities
and not over the department, and thus the operating orders
govern the responsibilities of only those entities. However, as
long as the department remains a party to the contracts, the
department clearly has significant ongoing responsibilities
for the administration of the contracts as well as the revenue
bonds. As we discuss more fully in Chapter 6, this responsibility
presents numerous challenges and risks for the department until
the contracts are transferred to the investor-owned utilities. n
8888 California State Auditor Report 2002-009 California State Auditor Report 2002-009 8899
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9900 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9911
CHAPTER 4
Sales of Surplus Power Have Not
Significantly Affected the Costs of
the Power-Purchasing Program
CHAPTER SUMMARY
As the Department of Water Resources (department)
progressed in supplying the net short, and market
prices stabilized in the summer of 2001, the long-term
implications of the contracts began to emerge. Our December 2001
audit report established that the department’s long-term contracts
would likely require it to purchase more power than would be
needed during some hours. Those quantities would be expected to
be sold as surplus and thus have the potential to affect the overall
costs of the department’s power program. However, the previous
report did not explore the financial effects of sales of surplus power,
or of sales from other sources made by the department as it sought
to fulfill its responsibilities under Assembly Bill 1 of the 2001–02
First Extraordinary Session (AB 1X).
The department’s sales of surplus power during 2001 and 2002
have remained small in relation to its volume of power purchases.
A certain level of surplus sales is a normal result of meeting
anticipated power demands using power-purchase contracts and
short-term purchases in advance of the demand period, rather
than relying too heavily on real-time or spot market purchases
when the power is needed. This surplus power can result from
more than one cause, such as unexpected changes in the weather,
purchase contracts that do not fit well with the demand for power
the department must fill, or fluctuations in forecasts of the net
short that are provided in seven-day, day-ahead, and hour-ahead
intervals by the investor-owned utilities to inform the department’s
traders of the expected upcoming demand for power.
Power sales during a given period do not necessarily result in
significant economic losses to the department. Indeed, some
sales may yield economic benefits. Sales of surplus power often
can entail anticipated losses that were taken into account when
making cost-effective purchase transactions. In a sense, such
losses are artificial. Some sales of surplus power, however, can
result in true economic losses. Our consultant advises us that
the cost that has resulted from the department’s sales of surplus
power does not appear unreasonable.
9900 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9911
SURPLUS POWER SALES INCREASED DURING 2002
BUT WERE NOT SIGNIFICANT COMPARED TO
POWER PURCHASES
The department made a considerable number of sales transactions
in the forward, day-ahead, and hour-ahead markets from
Sales of surplus power March 2001 through October 2002. However, from the standpoint
during the first three of transaction dollars and volumes, power sales were not a large
quarters of 2002 totaled part of the department’s activities. Sales revenues during the first
only about 3 percent three quarters of 2002 totaled $73 million, or only about 3 percent
of the total cost of the of the $2.6 billion total cost of the department’s energy program
department’s energy during that time. Similarly, sales volumes during the same period
program during that time. totaled 3,320 gigawatt-hours, or only 9 percent of the department’s
total purchase volumes of roughly 36,000 gigawatt-hours. Based
on our consultant’s review of the department’s purchase and
sales data from August 2002, they concluded that most sales
appear to have resulted from the shorter term buying and selling
required to manage the volatile net-short requirements. From
their analysis, it appears that less than 20 percent of the surplus
power sold is attributable to the department’s long-term contracts.
Figure 8 summarizes the department’s gross purchase and gross sales
transaction volumes for each month during 2001 and most of 2002.
In the months immediately following its February 2001 debut as
buyer of the investor-owned utilities’ net short, the department’s
focus was on obtaining sufficient supplies to ensure the
reliability of the California electrical system. Although its sales
transactions were very limited during the first four months of
2001, as Figure 8 shows, sales began to climb during the summer
of 2001. The department’s trading manager explained that the
department’s scheduled purchases were typically in balance with
the utilities’ forecasted net-short positions. However, department
records reflected a high percentage of sales made in response to
requests by the California Independent System Operator (ISO)
that the department step in to balance real-time consumer
demands and supplies in the California power system. The
department made out-of-market purchases and sales to perform
this real-time balancing function, which under normal market
conditions had been performed by the ISO.
9922 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9933
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On November 20, 2001, the Federal Energy Regulatory Commission
(FERC) ordered the ISO to stop relying on the department to
perform the market balancing function. As a consequence, the
department no longer routinely made out-of-market transactions
(either sales or purchases) on behalf of the ISO. Figure 9 on the
following page reflects the distinct drop in the department’s
sales of surplus power in the spot market after FERC’s order.
Figure 9 on the following page presents basic information regarding
the department’s sales activity. As we just noted, the substantial
real-time sales activity in the latter portion of 2001 reflects the
out-of-market transactions conducted by the department on behalf
of the ISO. The real-time volumes after November 2001, when
FERC issued its order, reflect occasional sales by the department to
the ISO. The figure also provides a view of the degree to which sales
were being made through short-term contracts. These short-term
contracts represent agreements the department struck in advance
to sell surplus nondispatchable power over periods ranging from
one day to three months. Figure 9 also shows the level of sales in
the day-ahead and hour-ahead markets.
9922 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9933
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FIGURE 8
Monthly Total Purchases and Sales During 2001 and 2002
Source: La Capra Associates’ analysis of data from the Department of Water Resources.
FIGURE 9
Monthly Summary of Sales by Type, 2001 Through 2002
Source: La Capra Associates’ analysis of data from the Department of Water Resources.
THE REASONS FOR THE DEPARTMENT’S SURPLUS
POWER SALES VARIED
The department faced a significant challenge in securing power
supplies to meet the net short. Several aspects of this challenge
are important relative to the level of sales transacted by the
department. For example, the magnitude of the net short is
substantial, comparable to or even exceeding the loads served
by many utilities, and is inherently quite variable, since the
electricity needs of California utility customers (like those of other
electric utilities) vary significantly from day to day and month to
month. Variations in the net short also occur from hour to hour
within each day. As we noted in our December 2001 audit, the
department’s net-short responsibility included buying roughly
Some level of surplus power one-third of the power requirements of the three investor-owned
is a normal result of a utilities. As such, the department was responsible for the most
prudent strategy to deliver volatile portion of power demand.
a low-cost reliable power
supply with limited reliance Some level of surplus power is a normal result of a prudent
on the spot market. strategy of any portfolio manager seeking to deliver a low-cost,
reliable power supply with limited reliance on the real-time or
9944 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9955
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spot markets. Overreliance on the real-time and spot markets
was a contributing factor to the power crisis in 2000 and 2001.
In the post-crisis conditions, relying on California’s real-time or
spot markets for supplies from which to serve the net short would
have brought significant risks of price volatility and (in temporary
instances of tight supply) reliability. The department chose to
mitigate these risks through forward, or advance, purchases of
power, in the form of long- and short-term contract commitments
made well in advance of delivery. Such forward purchases of
power result in surplus power when significant variations in the
net short inevitably occur.
The department uses forward purchases of power to mitigate
price and reliability risks that can be present in the real-time
or spot power markets. In the wholesale market, such forward
purchases are primarily available in blocks (for example, 6x16
products that deliver power six days a week, in 16 prescribed
hours a day) in which the delivery amounts by hour are fixed.
The sizable daily and even hourly variations in the net short
make it impossible to match such forward purchases to the net
short at all times. To allow utilities to cover shortages, power
suppliers may offer dispatchable products and other products
(such as “super peak” power) that provide power only when
needed. But such products are not always available in the
market, and they typically command premium prices. Thus,
supply portfolio managers often find it necessary or cost-
effective to rely a great deal on nondispatchable purchases of
standard 6x16 and 7x24 products to meet their needs. This
may be true even when those purchases are expected to lead
to surplus supplies during instances when (1) nondispatchable
quantities exceed the forecasted need during particular hours
or (2) the actual net short falls below forecast levels. In this
context, and given the market conditions, sales of surplus power
from long- and short-term contracts can be part of a cost-
effective portfolio management strategy.
In addition, the department’s surplus power sales volumes were
sometimes affected by downward revisions in forecasts of the net
The department’s surplus short provided by the investor-owned utilities. Sales can occur
power sales volumes were when the department increases its advance nondispatchable
sometimes affected by commitments in response to the day-ahead forecast for a given
downward revisions in hour, only to find that a subsequent reduction in the hour-ahead
forecasts of the net short forecast has rendered those purchases surplus. We also examined
provided by the investor- whether the department had taken advantage of relatively high-
owned utilities. market prices to sell its lower-cost contract supplies at a profit;
however, we did not find any instances in which the department
appeared to be using this strategy.
9944 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9955
A Small Portion of Sales Are Attributable to Surplus Capacity
From the Department’s Long-Term Contracts
Our consultant estimates that sales attributable to surplus power
from the department’s long-term contracts represented less than
20 percent of total sales during 2002, based on an evaluation of
surplus power sales in a targeted sampling of days during 2002.
To arrive at this estimate, our consultant developed a calculation
of the amounts by which nondispatchable volumes under the
department’s long-term contracts exceeded the hour-ahead net
short for each day during August 2002. Figure 9 on page 94 shows
that 2002 sales peaked during August. In Figure 10, we present the
quantities of surplus nondispatchable power beside the total sales
volumes for each day during that month. These energy surpluses
occurred even during a summer month when the net short was
typically quite large. However, Figure 10 reveals that the total
sales each day considerably exceeded the quantities of surplus
FIGURE 10
Surplus Power From Long-Term Contracts Versus Total Sales
August 2002
Source: La Capra Associates’ analysis of data from the Department of Water Resources.
9966 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9977
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power from the long-term contracts. Thus, only a fraction of
sales during August can be attributed to surplus power from the
department’s long-term contracts.
Figure 11 identifies sales made during peak and off-peak hours
during 2002. This figure is revealing in that the large portion of
sales during peak periods is consistent with a strategy of using
standard 6x16 blocks of power purchased through long-term
contracts to meet peak loads while anticipating some surpluses
during the lower-load hours of the 16-hour block. In fact, the
department discusses such a strategy in its plan to transition
responsibility for procuring the net short back to the investor-
owned utilities.
FIGURE 11
Sales During Daily Peak Versus Off-Peak Periods During 2002
Source: La Capra Associates’ analysis of data from the Department of Water Resources.
9966 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9977
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The December 2001 audit anticipated significant levels
of surplus energy as a consequence of the 7x24 and 6x16
nondispatchable volumes under the department’s long-term
contracts. During 2002 there were moderate increases in
quantities of nondispatchable capacity from long-term contracts
for 7x24 and 6x16 power products. These increases correspond
to increases in the quantities of surplus power during peak
periods. As nondispatchable power from the department’s long-
term contracts becomes an increasingly large portion of the power
purchases necessary to meet the overall net-short requirements,
the department’s ability to respond to variations in the net short
is increasingly constrained. In this light, the observation that
more sales occurred during peak hours is not unexpected.
Sales of Surplus Power From Short-Term Purchases Explain a
Significant Portion of the Department’s Sales During 2002
Much of the observed level of sales during 2002 appears to be
a result of short-term contract purchases that the department
made to cover the net short. Short-term contract purchases are
advance purchases for power supplies delivered across periods
ranging from one day to three months.
Figure 12 presents the results of an analysis of surplus power
from the department’s long- and short-term contracts relative
to total sales for five select days in August 2002. Like Figure 10,
it compares nondispatchable volumes to the hour-ahead net
short to calculate surplus energy levels in each day. Here,
however, nondispatchable volumes include those from both
long- and short-term contract purchases. Using the data from
Figure 12, our consultant concluded that a high percentage
of the department’s sales, almost 70 percent across the five
days, are attributable to the combined effects of long- and
short-term contract commitments. Our consultant indicates
that this pattern of surplus power sales is consistent with the
department’s strategy of using long- and short-term contracts
in an attempt to cost-effectively meet the net short and believes
that a similar percentage may apply to nondispatchable sales
throughout the year.
Note that the days that are the focus of Figure 12 represent
days with both high- and low-level of sales, corresponding to
days on which the most accurate estimates of the net short,
the hour-ahead forecasts, varied from relatively low to high, as
shown for the corresponding days in Figure 13 on page 100.
This is important because it shows, as would be expected, that
the department’s surpluses from nondispatchable contracts were
considerably smaller on the days when the hour-ahead forecast
net-short levels were high.
9988 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9999
FIGURE 12
Surplus Power From Long- and Short-Term Contracts Versus Total Sales
for Select Days During August 2002
Source: La Capra Associates’ analysis of data from the Department of Water Resources.
Figure 13 on the following page provides insight into the daily
challenges faced by the department in attempting to use forward
purchases of power to meet the net short during the month of
August. It reveals the magnitude of the daily swings in the net
short, as measured using the investor-owned utilities’ hour-ahead
forecasts. As the figure shows, on August 3 the net short peaked
at below 6,000 megawatts, while several days later peak net-short
levels were nearly double that level. Later in the month, the peak
net-short levels dropped back to 6,000 megawatts. Under such
conditions, making power purchases to ensure sufficient supplies
to meet peak-load conditions without causing at least occasional
surplus conditions would have been very difficult. In a market in
which concerns regarding the availability of cost-effective supplies
in spot markets made forward purchase commitments a necessity,
it probably was impossible.
9988 California State Auditor Report 2002-009 California State Auditor Report 2002-009 9999
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FIGURE 13
Daily Variations in the Hour-Ahead Forecast of the Net Short
During August 2002
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Source: La Capra Associates’ analysis of data from the Department of Water Resources.
Our consultant performed a detailed analysis of power sales
made on Monday, August 5, 2002. On that summer day, the
investor-owned utilities’ hour-ahead net-short forecast peaked at
roughly 7,000 megawatts during the 16th hour, considerably
below the roughly 12,000-megawatt peaks seen later in the
month. Figure 14 illustrates the hour-ahead purchase and sales
schedules that the department submitted to the ISO (through
the investor-owned utilities) for the day, as well as the day-
ahead and hour-ahead net-short forecasts that the department
received from the investor-owned utilities. In the figure, the hour-
ahead scheduled sales are stacked on the hour-ahead scheduled
purchases, net of sales, to represent the total scheduled purchases
for the day. These schedules and forecasts provide a view of the
department’s target at different points in time. The figure does
not, however, include spot market transactions to bring scheduled
purchases and sales in balance with actual demand.
110000 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110011
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FIGURE 14
The Hour-Ahead Schedule to the ISO, August 5, 2002
Source: La Capra Associates’ analysis of data from the Department of Water Resources.
Note: In this figure, hour-ahead scheduled sales are stacked on hour-ahead scheduled purchases, net of sales, to produce total
scheduled purchases.
Several items within Figure 14 are noteworthy. First, the figure
illustrates the surplus power inherent in blocks of power
purchased through the department’s long-term contracts.
This surplus is demonstrated where the total scheduled sales,
as represented by the blue area of the figure, shown below
the long-term, nondispatchable contract volumes in hours 1
through 10. Second, the department’s final scheduled purchase
amount, the amount of scheduled purchases, net of sales, tracks
fairly closely to the hour-ahead net-short forecast provided by
the investor-owned utilities. As we noted earlier, the department’s
staff indicated that this was their typical approach to scheduling
for a given day. Third, the increase in the net-short forecast from
the day-ahead to the hour-ahead forecast during the midday
hours caused the department to make additional purchases for
110000 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110011
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those hours. Finally, the figure shows that sales volumes for
August 5 considerably exceeded the levels of surplus energy
from long-term contracts. In fact, sales occurred in every hour
of the day. The department’s records show that, in addition to
its long-term contracts, the department had made short-term
contract purchases for delivery over the course of the month,
averaging approximately 1,500 megawatts during peak hours,
perhaps anticipating the typically higher net-short loads of the
month. The data supporting the figure show that on August 5,
a day in which the net short dropped below the average and
was well below the peak for the month, it was necessary for the
department to sell its short-term contract supply to bring its
portfolio into line with the net short.
As of January 1, 2003, the investor-owned utilities resumed
the responsibility for purchasing the residual net short. As part
of this responsibility, they will also manage the department’s
The department projects long-term contracts. In a December 2002 decision, the CPUC
increased surplus sales as stated that it has the exclusive authority to review the utilities’
more long-term contracts administration of the department’s contracts. The CPUC also
take effect. stated that it is responsible for monitoring the investor-owned
utilities’ sales of surplus power from the department’s long-term
contracts to mitigate the costs of these sales to the ratepayers.
However, because it retains legal and financial responsibility
for the contracts the utilities will administer, the department
will retain a role in observing the activities of the utilities and
working with the CPUC to ensure that the utilities comply with
the CPUC’s decision. The department projects increased surplus
sales as more long-term contracts take effect. In Chapter 6
we discuss the department’s future challenges in successfully
limiting sales of surplus power.
Limited Sales Resulted From Changing the Investor-Owned
Utilities’ Forecasts of the Net Short and Other Factors
The department’s sales volumes were sometimes affected by
downward revisions in the investor-owned utilities’ forecasts
of the net short. However, we did not find evidence that these
changing forecasts, particularly those involving downward
revisions in the projected net short, affected the department’s
surplus power sales activity in any consistent manner. Moreover,
we found no evidence that changes in the forecast led to a
meaningful level of unnecessary additional purchases by the
department. The investor-owned utilities routinely provided the
department with forecasts of their anticipated net-short position
seven days ahead of time (and for each hour of a given day), and
110022 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110033
then updated those forecasts on a day-ahead and hour-ahead
basis. Documents provided by the department indicate that
forecast changes frequently occurred in the transition from the
day-ahead forecasts to the hour-ahead forecasts. These changes
were occasionally of considerable magnitude. In Chapter 5 we
explore possible reasons for variations in the net-short forecasts.
Our consultant developed an analysis of variances in the
forecasts, using data from the department’s review of forecast
variances and by comparing the investor-owned utilities’
forecasts of hourly power demand from their day-ahead
forecasts to their hour-ahead forecasts for July, August, and
September 2002. Our consultants’ analysis revealed that for
almost 80 percent of the days in those months the change
between the total day-ahead and the total hour-ahead was
20 percent or less of the net short.
Our consultant then assessed the degree to which those changes
in forecast were causing the department to make sales. An
analysis of roughly 20 selected days in August and October
reveals that there were some instances in which reductions in
the forecast of the (total) net short coincided with sales in the
hour-ahead markets by the department. A reasonable conclusion
is that at least some sales were caused by the falling forecasts
provided by the investor-owned utilities. However, sales did not
always follow reductions in the forecast.
Other factors could have contributed to the observed levels of
sales activity during 2002. Notable among these would be the
sale of power from the department’s lower-cost dispatchable
contracts during periods when high prices in California’s spot
markets would enable the department to sell the power at a
profit. Such profits could, to a degree, offset the department’s
overall program costs. During the course of this audit, our
consultant performed a limited review of potential opportunities
for the department to profitably sell power from its dispatchable
contracts. We did not observe any instances in which it was
clear that power sales were resulting from such a strategy.
In this context it is notable that much of the department’s
dispatchable contract capacity in 2002 was from peaking units
with relatively high production costs. It would be cost-effective
for the department to resell power from these contracts only
when market prices exceed the cost of the contract energy. We
did not observe any instances in which market prices may have
been high enough to justify the dispatch of the department’s
110022 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110033
peak-hour contracts. Moreover, documents provided by the
department show that it does not view that its mandate under
AB 1X allows speculative trading.
POWER SALES CAN BE COSTLY, BUT THEY DO NOT
NECESSARILY RESULT IN SIGNIFICANT ECONOMIC LOSSES
The department, like other market participants, often made
short-term purchases, expecting to resell some of the power
during days or hours when the net short was lower than average.
However, sales of surplus power from short-term contracts (for
example, monthly or quarterly forward purchase commitments
made during 2002 for delivery in 2002) would not necessarily
represent a significant financial loss. If market prices are relatively
stable and the surplus is resold at a price that approximates the
cost of the power, no material loss would be realized. This appears
to have been the case during much of 2002, when market prices
were much more stable than in 2001. The prices of the short-term
contracts created in 2002 were not nearly as high as the contracts
the department signed in early 2001.
Some losses were realized on the sale of surplus power
from long-term contracts. However, these losses were likely
smaller than they might appear. Our consultant estimated
The department suffered the apparent loss on sales of surplus long-term contract power
some losses on the sale of in August 2002. The calculation simply contrasted the average
surplus power from long- cost of long-term contract purchases made for August supplies
term contracts. to the average amount received from power sales during that
month, using data provided by the department. The calculation
identified average purchase prices that exceeded average sales
prices by $58.54 per megawatt-hour, representing an apparent
loss of $6.8 million on surplus energy volumes of just over
116,000 megawatt-hours. This simplified calculation likely
overstates the department’s true loss from such sales, however.
To be sure, market prices have fallen greatly since the
department’s long-term contracts were signed in the first half of
2001. During 2002, conditions in California’s electricity markets
continued to improve. Average power costs were considerably
lower and more stable than had been witnessed at the height of
the crisis. Power prices declined through midsummer 2001 and
remained relatively low through the balance of 2001 and 2002.
Average power costs in 2002, as reported by the ISO and including
costs in the department’s power portfolio, were under $50 per
megawatt-hour. Data from the Dow Jones index of daily prices
110044 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110055
indicate that power in California’s markets frequently traded at
below $35 per megawatt-hour. These figures are only a fraction
of the $300-plus per megawatt-hour prices seen during the peak
of the crisis in December 2000. As a result, the prices that the
department received in 2002 for its sales were certainly lower than
the price it committed to pay for the long-term contract energy.
In this sense, the sale of surplus energy from the department’s
long-term contracts has entailed some financial loss.
However, our consultant indicates that a proper quantification
of such losses would be a complicated exercise. Assessing the
economics of surplus power sales by the department would,
for example, require estimating the value of power purchases
relative to selling prices on an hourly basis. Also, the surplus
energy that the department bought under its long-term
contracts provided value in that it was at least an imperfect
hedge against higher spot market prices that could have
occurred (but did not). Therefore, we have not quantified the
losses associated with sales of surplus long-term contract energy.
Figure 15 on the following page provides additional insight into
the effects of sales of surplus power on the department’s overall
supply portfolio. The “purchases only” bars represent the gross
average cost of power for the department’s entire portfolio of
purchases during each month of 2002. Gross purchases include
The effect of power power that the department obtained from its long- and short-
sales over the course of term contracts, day-ahead purchases, hour-ahead purchases,
2002 was to increase and real-time purchases. The “purchases, adjusted for losses
the effective per-unit on sales of surplus power” bars represent the net average cost
cost of the overall power of power for the department’s entire portfolio; that is, they
supply portfolio by more show average power costs after factoring in the economic losses
than $6 per megawatt- that resulted from the sales of surplus power. The figure shows
hour, an amount our that the department’s power sales reduced its total quantity of
consultant advises does power somewhat more—in relative terms—than they reduced
not appear unreasonable overall power costs. Thus, the effect of power sales over the
course of 2002 was to increase the effective per-unit cost of the
overall power supply portfolio by more than $6 per megawatt-
hour. Our consultant advises us that, all else being equal, this
differential in gross and net average power costs does not
appear unreasonable. Moreover, had the department purchased
nonstandard products that would have enabled it to meet the
net short exactly in all hours of 2002 (that is, without any sales),
its average power costs might have been even higher.
110044 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110055
FIGURE 15
Average Cost of the Power Portfolio During 2002
Source: La Capra Associates’ analysis of data from the Department of Water Resources.
110066 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110077
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A review of the department’s sales records and ISO invoices
reveals that on occasion the department made power sales in
the hour-ahead markets only to have the ISO purchase power on
its behalf in the spot market to meet the net short. In a limited
review, we identified two days during which the department’s
total costs increased by roughly $60,000 and $40,000 because it
sold power in the hour-ahead markets at relatively low prices,
followed by real-time purchases by the ISO at a higher cost to
meet the net short. During other days we reviewed, we saw
no evidence of such activity. To some degree, such costs are
inevitable because of the complexities of scheduling power
supplies as real time approaches. For the same reason, it is
difficult to estimate the extent to which such costs were, in
fact, avoidable. We do not have evidence that such repurchase
activity represented a fundamental problem. n
CHAPTER 5
The Department Was Not Able to
Achieve Coordinated Dispatch of Power
Supplies That Could Reduce Costs
CHAPTER SUMMARY
The electric power that the retail customers of the investor-
owned utilities receive is produced from a variety of
sources, each with different costs per unit of power
delivered during different times of the day and week. The sources
include hydroelectric dams, nuclear, and fossil fuel-fired power
plants owned by the investor-owned utilities, as well as a variety
of contracts with suppliers entered into by the Department
of Water Resources (department) and the investor-owned
utilities. As such, there is an opportunity each day to provide
electric power to the utilities’ retail customers from a mix of
sources—some controlled by the utilities and some controlled
by the department—that results in the lowest possible price
to ratepayers. In our December 2001 audit, we cite a specific
example in which small savings in daily power costs could result
in annualized savings to the ratepayers representing potentially
tens of millions of dollars.
The department has achieved improvements in its portfolio
of power-purchase contracts and gained experience in trading
in California’s wholesale power markets. While these factors
enhanced its ability to implement a coordinated dispatch, the
department and the investor-owned utilities did not establish
the structures and mechanisms that would have enabled them
to coordinate the dispatch of power to minimize costs to
ratepayers in 2002. The reasons that a coordinated dispatch
was not achieved are not entirely clear, but the department had
two concerns in this regard: the investor-owned utilities’ failure
to share information about the availability of their generating
facilities and the terms of their contracts with suppliers, and
frequent and sometimes substantial changes in the net-short
forecasts prepared by the investor-owned utilities.
110066 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110077
THE DEPARTMENT DID NOT ACHIEVE A
COORDINATED DISPATCH OF ITS POWER
SUPPLIES AND UTILITY RESOURCES
Although the potential existed, the department was not successful
The department believes in its attempts to interact with the investor-owned utilities to
that coordinating coordinate all of the electric power resources available to them to
the dispatch of the ensure that they provided the lowest-cost power to the utilities’
department’s contracts retail customers. In our December 2001 audit, we indicated
and the investor-owned that better opportunities existed for coordination between the
utilities’ generating department’s supply resources and the investor-owned utilities’
assets during 2002 generating assets. The department believes that coordinating
could potentially have the dispatch of its contracts and the investor-owned utilities’
reduced overall costs generating assets during 2002 could potentially have reduced
to retail customers by a overall costs to retail customers by a substantial amount.
substantial amount.
Our December 2001 audit suggested several ways in which
coordinated dispatch decisions could bring savings to
California’s ratepayers. For example, our audit indicated that it
may have been possible to reshape hourly dispatch schedules of
the investor-owned utilities’ hydropower facilities to minimize
the cost of the department’s purchases. The utilities might also
have reduced the output of their thermal units occasionally
when spot market prices were low and increased the output of
their thermal units when spot market prices were high. Our
December 2001 audit also pointed to the hydropower units as a
potentially low-cost source of power for needed power reserves.
It indicated that the department’s staff and consultants believed
that a coordinated dispatch could achieve meaningful savings,
but that they were not able to reach a full understanding of the
magnitude of savings that such a dispatch could attain.
During 2002 the department pursued coordination to tailor the
investor-owned utilities’ hydroelectric energy production to
promote a least-cost dispatch of power to their retail customers,
but it was not successful in its attempts to engage Southern
California Edison (SCE) and Pacific Gas & Electric (PG&E)
in the effort. The department suggested that the dispatch of
each utility’s hydropower facilities be coordinated with that of
its own contracts. The goal was to enable the department to
minimize its purchase of expensive, nonstandard products, such
as power for “super peak” periods and power for a particular
hour of the day, which were otherwise required to cover the
net short as it changed from hour to hour. The department
had concluded that the investor-owned utilities’ hydropower
facilities could be dispatched to perform this matching of loads
110088 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110099
and resources in a manner that would not alter the total output
of a given hydropower facility across a given day. Preserving
the total daily output was expected to ensure that the utilities’
revenues would not be affected by the coordinated dispatch.
Documents provided by the department include estimates
of potential savings. For example, for the single day of
March 5, 2002, the department estimated that using PG&E’s
hydropower facilities to lessen the need for spot market
purchases to meet the net short would potentially have saved
$115,000. A similar estimate for SCE suggested daily savings of
the same order. The department’s documents did not address
the degree to which the days analyzed might be representative
of savings across a broader period. However, our consultant’s
analysis of the department’s calculations suggests that, if such
savings could have been replicated across even one in every
four days, cumulative annual savings to ratepayers could exceed
$20 million in any given year.
During 2002 the Opportunity Remained to Optimize the
Overall Dispatch to Benefit Ratepayers
The opportunity to pursue savings through a coordinated
dispatch remained throughout 2002. The investor-owned
utilities’ hydropower facilities continued to represent a flexible
resource that, through coordination with the department, could
have been used to reduce total power costs. A coordinated
The investor-owned dispatch also would have brought savings by making the best
utilities’ hydropower use of the investor-owned utilities’ and the department’s power
facilities continued to supplies relative to a given set of market prices and consumer
represent a flexible demand levels.
resource that, through
coordination with the As we discussed in Chapter 1, a number of the department’s
department, could have long-term contracts have been renegotiated to reduce
been used to reduce total the proportion of the power volume provided through
power costs. nondispatchable contracts and to increase the proportion of
dispatchable power. Table 2 in Chapter 1 shows that while the
amount of nondispatchable power supplied by the department’s
long-term contracts increased somewhat during 2002 as a
consequence of contract renegotiations, proportionate to
the department’s total contract portfolio, the share of power
volumes from nondispatchable contracts shrinks while the share
from dispatchable contracts grows. As a consequence, during
2002 the department was better positioned to match its contract
supplies to consumer demand and to respond effectively to
changing market conditions on a daily and hourly basis.
110088 California State Auditor Report 2002-009 California State Auditor Report 2002-009 110099
The Reasons That a Coordinated Dispatch Was Not Achieved
During 2002 Are Not Entirely Clear, but the Department
Identified Two Notable Concerns
The reasons that further progress was not made in coordinating
the hydropower dispatch are not entirely clear. The department
indicated that it received no written proposal or counterproposal
Without sufficient details from any investor-owned utility on how to improve the overall
of the availability of dispatch. According to the department, during 2002 the
the utilities’ generating investor-owned utilities did not share sufficient details related
facilities or price and to the availability of utility-retained generating facilities or
dispatchability terms information on the basic price and dispatchability terms of their
of their contracts with contracts with suppliers. Without this essential information, the
suppliers, the department department could not have reliably anticipated the dispatch of
could not have acted on the investor-owned utilities’ generating sources and acted on
opportunities to reduce opportunities to reduce the overall dispatch costs.
the overall dispatch costs.
Coordination issues aside, the investor-owned utilities’ changing
forecasts of the net short likely increased the department’s
difficulties in optimizing its dispatch to best serve the net short.
The department’s documents indicate that its schedulers were
quite dependent on the investor-owned utilities for accurate
forecasts of the net short. The net short is important to a
discussion of coordinated dispatch because it is derived as the
difference between estimated total demand and the power
provided from the utilities’ generation and from contracts for
power from the portfolios of both the department and the
investor-owned utilities. Although the department and its
consultants reviewed the various forecasts, they did not have
access to important data and underlying assumptions regarding
customer demand and power-generation capabilities. As we
discussed in Chapter 4, the investor-owned utilities’ net-short
forecasts changed regularly and in amounts that occasionally
were substantial.
The department’s staff indicated that it sought to discuss the
causes behind the changed net-short forecasts with utility
personnel but obtained little information. The department
performed an analysis of the magnitude of changes in the
investor-owned utilities’ day-ahead net-short forecasts relative
to those provided on an hour-ahead basis. According to the
department, the only documents outlining the results of its
investigation into the causes of those forecast changes exist
in the form of an e-mail exchange between the department’s
trading manager and an individual at SCE. The trading manager
expressed concern with SCE’s substantial changes (from 400 to
1,150 megawatts in some hours) between its day-ahead forecast
111100 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111111
and its hour-ahead forecast for Sunday, September 15, 2002,
and indicated that those changes were forcing the department
to purchase large amounts of power on short notice. She stated
that “this typically causes prices to drive up and may cause
difficulty in managing and meeting the net short requirement.”
The response that the trading manager received to her question
as to what was causing the changes was simply, “The same
things that always change (and always will): load and QFs.”
(Qualifying facilities (QFs) refers to suppliers of power through
contracts held by the investor-owned utilities.)
The forecast changes may have reflected more than just natural
supply and demand fluctuations or imprecise forecasting by
the investor-owned utilities. During the course of this audit,
department personnel expressed concerns about the potential
for the investor-owned utilities to “game” the dispatch of power
from their various sources to maximize their revenues at the
expense of ratepayers. They stated that the investor-owned
utilities had never provided the department with sufficient
information to understand how the utilities dispatch their
power resources. In a July 30, 2002, letter to the California
Public Utilities Commission (CPUC) regarding the need for
operating agreements between the department and the utilities,
the department expressed its desire for the CPUC to order
the utilities to implement an approach in serving their retail
customers that utilizes all of the department’s nondispatchable
power and results in a least-cost dispatch of power to retail
customers. This audit did not address the details of the CPUC’s
ratemaking practices relative to power supplies from the
department and the investor-owned utilities.
As we mention in Chapter 6, part of the utilities’ responsibility
for purchasing the net short will be to manage the department’s
long-term contracts. The CPUC has stated that it has the
exclusive authority to review the utilities’ administration of the
department’s contracts, and it has also stated that it is responsible
for monitoring the investor-owned utilities’ sales of surplus power
from the department’s long-term contracts to mitigate the costs
of these sales to the ratepayers. However, because it retains legal
and financial responsibility for the contracts the utilities will
administer, the department will retain a role in observing the
activities of the utilities and working with the CPUC to ensure
that the utilities comply with the CPUC’s decision. In Chapter 6
we discuss the department’s future challenges in working with
the utilities and the CPUC to ensure least-cost dispatch of power
resources to the utilities’ retail customers. n
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111122 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111133
CHAPTER 6
The Department Will Continue to
Face Cost and Legal Challenges
CHAPTER SUMMARY
Two years ago, Assembly Bill 1 of the 2001–02 First
Extraordinary Session (AB 1X) established the Department
of Water Resources (department), on behalf of the State,
as the sole buyer of power for the substantial unmet needs
of the consumers served by Pacific Gas & Electric (PG&E),
Southern California Edison (SCE), and San Diego Gas & Electric
(SDG&E), the State’s three largest investor-owned utilities. This
responsibility came in the midst of, and was in direct response
to, an unprecedented crisis that included financial insolvency
of the utilities, shortages of power supplies, exorbitant prices,
and what the Federal Energy Regulatory Commission (FERC)
concluded was a dysfunctional power market. Today, two years
later, the crisis conditions have substantially abated and
the department’s buying authority under AB 1X has ended.
However, substantial work remains to be done by others to
restore California’s electric markets to full health and to manage
the power portfolio assembled by the department during its
two-year tenure as power buyer for the State.
Many aspects of the State’s power market still require substantial
action. PG&E and SCE each have important challenges left before
they can become restored to full financial viability as buyers of
power. The California Public Utilities Commission (CPUC) is
developing rules that will govern the utilities’ power-procurement
practices over the longer term. The California Independent System
Operator (ISO) is now engaged in a multiphased process to develop
and implement a number of changes to its market structure,
needed to ensure that the markets are effective and well monitored.
California’s power supply situation has improved over the past
two years, as 8,000 megawatts of new supplies have or will soon
come into operation. Accounting and credit issues have affected
many companies in the power supply industry over the past year,
leading to restructuring in the industry and changes in financial
accounting systems and raising questions regarding the further
development of new power supplies in the market. Substantial
outstanding investigations and litigation associated with the power
crisis remain unresolved. This range of activities makes clear that
much remains to be done to stabilize the State’s power markets.
111122 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111133
The department’s ongoing stewardship of the Electric Power
Fund and the power contract portfolio will be an important
component of the State’s power supply for years to come.
Financial and legal responsibility for the portfolio of power
contracts is likely to remain with the department for much
of the next decade and will require continued vigilance to
mitigate the high costs of those contracts to the extent possible.
Attendant upon those management responsibilities will be the
need for the department to manage its operating partnerships
with the utilities to schedule and deliver the power and to
procure fuel. In addition, the department will retain continued
management of the Electric Power Fund and the administration
of the bonds issued to finance the cost of the AB 1X power
program. These remaining responsibilities carry substantial
ongoing obligations to manage costs and risks and will require
a sustained professional organization at the department to
properly protect the State’s interests.
THE STATE HAS MUCH LEFT TO DO TO SUCCESSFULLY
RESTORE THE ELECTRICITY MARKETS
While the department’s role as power buyer on behalf of the
State has ended, this milestone does not signal the end of the
challenges facing the State in restoring the power markets.
Continued diligence in many areas remains necessary to ensure
that the State can avoid a return to the crisis conditions of
two years ago. Many of these challenges are outside of the
department’s responsibilities.
Two Investor-Owned Utilities Have Not Yet Regained
Creditworthiness
AB 1X was implemented in February 2001 to establish an entity,
the department, that had the financial capability to buy power
Only one of three on behalf of PG&E, SCE, and SDG&E at a time when those
investor-owned utilities utilities had become financially unable to do so. Today, SDG&E
meets the investment- is the only one of these utilities that meets the investment-grade
grade rating standard of credit rating standard of creditworthiness.
creditworthiness.
As of January 1, 2003, PG&E remained in bankruptcy. The
bankruptcy court has two competing plans for reorganization
before it and has scheduled substantial hearings on these
completing plans in February and March of 2003. It remains
unclear when this bankruptcy will be resolved, what the
reorganized company will be, and when a fully creditworthy
111144 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111155
utility will be established. To reestablish its ability to buy power
to meet its net-short requirement, PG&E was required to post a
security deposit with the ISO.
SCE began 2003 with a credit rating below investment grade. The
company has been operating under a rate settlement agreement
with the CPUC that provides for the repayment of debts incurred
during the power crisis. SCE has projected that, under the
agreement, by the end of 2003, it expects to recover all of the
costs to procure power during the energy crisis that it was not
previously able to charge to its customers. This agreement is now
the subject of a legal challenge and is scheduled to be considered
by the California Supreme Court in March 2003. Notwithstanding
Despite creditworthiness its below-investment-grade standing, SCE has been able to resume
issues, each utility began power-procurement responsibilities.
2003 with sufficient
ability to resume buying Nevertheless, each of the utilities began 2003 with sufficient
power supplies, aided ability to resume buying power supplies needed to meet its
substantially by lower respective net-short position. This ability to resume procurement,
market prices and despite the lack of full creditworthiness by PG&E and SCE, was
reduced residual net- aided by the substantially lower prices in the market and by
short requirements. the significant reduction in the residual net-short requirements
resulting from the department’s power contract portfolio.
Regulations Governing the Investor-Owned Utilities’
Responsibilities for Power Procurement Are Being Developed
AB 1X provided the department with the authority to assemble
a portfolio of power-supply contracts, an authority distinct from
the more limited authority that the investor-owned utilities
had in 2000 and that they were financially unable to perform
in 2001. The Legislature and CPUC took steps in 2002 to create
a statutory and regulatory framework to give the utilities the
authority to secure long-term supplies and to transfer the power-
procurement function to the utilities. These actions fostered the
return of the power-procurement responsibility to the utilities
from the department on January 1, 2003, and established a
framework for long-term power-procurement planning and
implementation by the utilities.
Assembly Bill 57 (AB 57), signed into law in September 2002,
included statutory provisions to allocate the contracts in
the department’s portfolio to the utilities; to require the
investor-owned utilities to optimize the utilization of the
overall portfolio, including the department’s contracts; and
to otherwise enable the utilities to reassume the responsibility
111144 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111155
for procuring power. In addition, AB 57 established
requirements for a long-term procurement planning process
to be conducted by the utilities under CPUC regulation. This
responsibility for portfolio planning and procurement is akin
to the responsibility vested in the department by AB 1X in
2001 and 2002. Prior to AB 1X, the utilities were restricted in
their procurement responsibilities to reliance on spot market
transactions and limited short-term contracts.
Senate Bill 1078 (SB 1078), also enacted in September 2002,
established a renewable portfolio standard requiring utilities
to increase their reliance on renewable sources of power and
to ultimately obtain 20 percent of the power needed for retail
sales from renewable sources by December 2017. Before they can
make procurements under this statute, the utilities must first
regain creditworthiness by attaining an investment-grade rating.
In concert with these legislative actions, the CPUC took
actions to implement the utilities’ return to the procurement
function. In August 2002, the CPUC authorized an accelerated
power-procurement process that authorized PG&E and SCE to
solicit power to be contracted in tandem with the department
before the year’s end. This interim procurement process was
intended to further minimize the amounts of power that these
utilities would need to procure on their own in 2003. The SCE
did complete several capacity contracts using this process and
the department indicates that it signed agreements with two
suppliers for PG&E.
In September 2002, the CPUC allocated the department’s
contracts among the three investor-owned utilities. This
In October 2002, allocation is displayed in Table 15. This contract allocation
the CPUC issued an provided a basis from which each utility could then determine
order directing all its remaining needs for power supply and develop procurement
three investor-owned plans for January 2003 and beyond. It also established those
utilities to resume contracts for which each utility would assume operating
power-procurement responsibility in 2003.
responsibilities on
January 1, 2003, and In October 2002, the CPUC issued an order directing all
establishing a regulatory three investor-owned utilities to resume power-procurement
framework for the responsibilities on January 1, 2003, and establishing a regulatory
utilities’ forthcoming framework for the process of planning and implementing the
procurement activities utilities’ forthcoming procurement activities under AB 57.
under Assembly Bill 57. In this order, the CPUC made provisions for the adoption of
interim procurement plans that would serve as the basis for the
start of procurement in 2003. In addition, the CPUC initiated
a process for developing long-term procurement plans for each
111166 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111177
TABLE 15
Adopted Allocation of Department Contracts
Long-Term Contract Contract Category Adopted Allocation
Allegheny 2 (150 MW 6x16 in NP15 for 2003) Nondispatchable PG&E
Calpine 1 Product 1 Nondispatchable PG&E
Calpine 2 Product 1 Nondispatchable PG&E
Capitol Power * Nondispatchable PG&E
Clearwood Nondispatchable PG&E
Constellation - Product 2 (400 MW 7x24 May to October 2003) Nondispatchable PG&E
Coral Nondispatchable PG&E
El Paso (50 MW 6x16 in NP15) Nondispatchable PG&E
Intercom Nondispatchable PG&E
Santa Cruz Nondispatchable PG&E
Soledad Nondispatchable PG&E
Allegheny 1 (Excluding NP15 deliveries) Nondispatchable SCE
Constellation (200 MW 6x16 through June 2003) Nondispatchable SCE
Dynegy Nondispatchable SCE
El Paso (50 MW 6x16 in SP15) Nondispatchable SCE
Morgan Stanley Nondispatchable SDG&E
PG&E Nondispatchable SCE
Primary Power Nondispatchable SDG&E
Sempra Nondispatchable SCE
Cabazon Nondispatchable SDG&E
Whitewater Hill Nondispatchable SDG&E
Williams Nondispatchable SDG&E
Calpine 1 - Product 2 Dispatchable PG&E
Calpine 2 - Products 3 & 4 Dispatchable PG&E
Calpine 3 Dispatchable PG&E
Calpine SJ Dispatchable PG&E
Calpeak (3 contracts) New Site, Panoche, and Vaca-Dixon Dispatchable PG&E
GWF Dispatchable PG&E
Pacificorp Dispatchable PG&E
Wellhead Power (3 contracts) Fresno, Gates, and Panoche Dispatchable PG&E
Alliance (now Colton Power) Dispatchable SCE
Calpeak (3 contracts) Border, El Cajon, and Escondido Dispatchable SDG&E
Dynegy (1,000 MW Peak System Contingent) Dispatchable SCE
High Desert Dispatchable SCE
Sunrise Dispatchable SDG&E
Source: California Public Utilities Commission (CPUC) Decision 02-09-053, Table 1, September 19, 2002. The contract category
reflects the category the CPUC used in its decision.
* The department later terminated the contract with the supplier.
MW = Megawatts
111166 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111177
utility and for implementing the renewable portfolio standard
in 2003. Each utility will file proposed long-term procurement
plans in April 2003 for consideration in subsequent adjudicatory
proceedings to be conducted by the CPUC to ensure that it
complies with the framework established by AB 57, SB 1078, and
the CPUC’s October 2002 order. The CPUC and the California
Energy Commission (energy commission) will also jointly
determine procedures for implementing the renewable portfolio
standard. These legislative and regulatory actions are designed to
restore the utilities as effective, long-term providers of the power
supplies needed for consumers in their respective service territories.
Enhancements to the Wholesale Power Market Are Not
Yet Implemented
The department’s power-buying authority under AB 1X came
While the actions taken at a time when FERC concluded the wholesale markets were
by the ISO and FERC dysfunctional. The ISO and FERC have taken steps toward the
have contributed to the wholesale market reforms needed to address the dysfunctions
stabilization of market that were at the center of the crisis two years ago. While the
conditions, substantial actions taken have contributed to the stabilization of market
work remains to conditions, substantial work remains to implement the reforms
implement the reforms necessary to fully restructure the market.
necessary to fully
restructure the market. In June 2001, FERC ordered a set of price mitigation measures
to be applied throughout western markets. These measures were
to be in effect through September 2002 to allow time for the
development of long-term structural reforms.
In April 2002, the ISO put forth a Comprehensive Market Design
Proposal (redesign proposal). This proposal is a three-phased,
multiyear effort to undertake a comprehensive redesign of its
market systems. It includes improved methods of mitigating
the potential for the exercise of market power, managing the
congestion within the transmission system, and improving the
structure of the spot markets and real-time operation of the market.
In July 2002, FERC authorized an extension of the price
mitigation measures beyond the original September 2002
endpoint. These measures require all in-state non-hydropower
generating units to bid all available capacity into the ISO’s
market in all hours and place a bid price cap of $250 per
megawatt-hour on power for all western markets. These market
111188 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111199
protections will apply until the ISO is able to implement further
market reforms and FERC concludes its investigations of market
power and market manipulation in western markets.
According to the ISO, on October 30, 2002, phase 1a of the
redesign proposal went into effect, including the price cap and
automated mitigation procedures. These procedures apply a set of
price screens to bid prices offered by generators, with automatic
adjustments to the bids applied if the bids fail the price tests.
These mitigation procedures will ensure that bid prices above
competitive levels will not be accepted or affect market prices.
As of December 2002, the ISO’s schedule for implementing the
redesign proposal calls for completing the remaining phases
of the proposal by the summer of 2004. The actual design and
implementation schedule remain subject to further proposals
and FERC approvals.
The Outlook for the Power Supply Infrastructure Is Improving
Shortages in supplies of power and limitations in transmission
infrastructure contributed to the power crisis. Over the past two
years, substantial progress has been made in the development of
power supply and transmission infrastructure.
The energy commission recently reported that the State’s
power supply situation has improved over the past two years
and that its supply outlook is good in the near term. In
Over the past two years, California, 18 new power plants totaling 4,980 megawatts
18 new power plants have become operational in the past two years, with an
totaling 4,980 megawatts additional 3,106 megawatts from seven more plants due on-
have become operational, line by August 2003. These approximately 8,000 megawatts
with an additional have been matched by a like amount of new capacity in other
3,106 megawatts from locations in the western marketplace. The energy commission’s
seven more plants due current outlook indicates that supplies are expected to be
online by August 2003. sufficient to meet summer peak requirements over the near term.
The development of new supplies has been partially offset by
generation retirements. The ISO reports that requirements for
additional pollution controls by the end of 2003 are contributing
to the closing of 948 megawatts of older peaking units.
ISO operations have shown improvement in maintaining sufficient
reserves of energy to continue operations with minimal declaration
of emergencies since the crisis of 2000 and 2001. The number of
declared emergencies in 2002 was closer to the number in the years
before the crisis, as shown in Table 16 on the following page.
111188 California State Auditor Report 2002-009 California State Auditor Report 2002-009 111199
TABLE 16
Declared Emergencies Over the Past Five Years
Declaration 1998 1999 2000 2001 2002*
Alert 7 2 34 180 3
Warning 8 6 85 181 4
Stage 1 Emergency 7 4 55 70 2
Stage 2 Emergency 5 1 36 65 1
Stage 3 Emergency 0 0 1 38 0
Source: California Independent System Operator 2002–03 Winter Assessment.
*January through September 5, 2002, data.
In addition to power supplies, transmission bottlenecks have
been a concern. Most notably, a transmission linkage known
as Path 15 has been a limiting factor in power transfers
between Northern and Southern California. The ISO has
observed that prior pressures on Path 15 have been reduced
more recently, as significant new generation has been added
in Northern California. For example, in the first nine months
of 2002, 2,283 megawatts of 2,771 total new megawatts in
California were located north of Path 15. Further improvement
in Path 15 interconnection is planned. The Western Area
Power Administration, PG&E, and Trans-Elect, Inc. recently
completed a construction agreement to add a new 500-kilovolt
line to this interface, increasing north-south transfer capacity
by 1,500 megawatts. In February 2003, the Western Area Power
Association reported that this project is planned for completion
in late 2004.
The Commercial Power Industry Is Under Significant
Financial Stress
The high market prices during the California power crisis
created a financial crisis for power buyers, notably PG&E, SCE,
The well-chronicled the Power Exchange, and, initially, the department. Subsequent
collapse of Enron in events in the markets have led to substantial financial turmoil
late 2001 is an example for commercial power producers and wholesale power-trading
of the unprecedented entities, raising significant questions regarding the financial
reversal in financial health ability of the industry to proceed with needed investment.
throughout the commercial
power industry. The well-chronicled collapse of Enron in late 2001 is an example
of the unprecedented reversal in financial health throughout the
commercial power industry. The troubles in this industry can be
112200 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112211
attributed to several factors. Problems with accounting practices
at Enron and, to a lesser degree, throughout the industry, have
caused significant restatements of earnings and modification
to practices and standards. Enron and several other market
participants have acknowledged participating in certain trading
activities that may be found to be illegal, as well as in improper
price reporting in the California market, leading to indictments
Surplus power supply, and ongoing investigations of trading activities by FERC, the
depressed price margins, Securities and Exchange Commission, the Department of Justice,
and tighter credit and the Commodity Futures Trading Commission. In addition
requirements have led to these legal troubles, the recent development of commercial
many to expect a debt generation projects nationally has led to surplus power supply
crisis in the industry in and depressed price margins. These lower prices, combined with
the coming months. tighter credit requirements, have placed substantial financial
pressure on all generation companies. Power-trading businesses
have also substantially diminished, as several formerly
major traders, such as Enron, El Paso, Aquilla, and Dynegy,
have eliminated their trading functions, while others have
substantially scaled back trading activities.
These problems in the industry have led many to expect a debt
crisis in the industry in the coming months. These financial
pressures affect many participants in California’s markets, as
credit downgrades are now widespread and many are deferring
or canceling investments to improve their financial positions.
For example, AES recently announced losses of $3.5 billion for
2002 and a $400 million write-off for a partially constructed
and now suspended 1,100-megawatt plant in Redlands. The
California Power Authority, in its recent draft investment
plan, noted that the majority of major generation participants
in California stand at or near junk investment status. In this
context, continued improvement in the power supply situation
in California will depend upon planned improvements in
accounting and business practices in the industry and resolution
of the current credit crisis in the commercial power industry.
THE DEPARTMENT REMAINS THE HOLDER OF A
SIGNIFICANT PORTFOLIO OF HIGH-PRICED CONTRACTS,
REQUIRING ONGOING DILIGENCE IN SEEKING REFORMS
AND IMPROVEMENTS TO MITIGATE THOSE COSTS
Although the department’s AB 1X authority to enter into
new contracts to buy power has come to an end, the
substantial power contract portfolio it acquired remains.
The department remains legally and financially responsible
112200 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112211
for those contracts and retains authority under AB 1X to
carry out that responsibility. As we noted in Chapter 3, the
renegotiated contracts now contain provisions that provide for
the transfer of some contracts to the investor-owned utilities
when creditworthiness standards are met and the CPUC issues
an order finding the contracts just and reasonable. However,
even if all of these transfers occur, approximately half of the
power under contract could remain with the department for the
duration of the contracts. As we noted in our December 2001
The department’s audit, the original contracts do not include strong provisions for
substantial efforts to assignment or transfer to the utilities.
seek opportunities to
renegotiate the contracts The department’s challenges in managing this power contact
over the past year have portfolio are very similar to those discussed in our December 2001
produced important audit. Despite the progress made in restructuring several of
improvements, but many the contracts, the portfolio remains substantially more costly
of the problems still remain than projected market prices, as we noted in Chapter 2. For
in the original contracts. those contracts that have not been renegotiated, the many
problematic provisions identified in the previous audit remain.
The department’s substantial efforts to seek opportunities to
renegotiate the contracts over the past year have produced
important improvements, but many of the problems still remain
in the original contracts.
Despite the problematic aspects of the portfolio, the power
supplies secured by these contracts remain important to the
stabilization and recovery of the California power markets.
The department’s contracts together with the investor-owned
utilities’ own sources of supply secure over 90 percent of the
power needed in the near term, thus reducing the volume
of power that the utilities must purchase. This is particularly
important for PG&E and SCE while they work toward their
return to financial health.
The department’s program going forward should continue
to manage the contracts aggressively to develop and capture
opportunities to improve the contract portfolio, in terms of
both cost and reliability. Further opportunities may develop due
to the current credit crisis affecting many of the suppliers in
the industry. Over time, as the situation of individual suppliers
or conditions in the market change, other opportunities may
develop. A sustained and systematic contract management
program over time is necessary, given the size of the portfolio.
112222 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112233
THE DEPARTMENT RETAINS SIGNIFICANT ONGOING
RESPONSIBILITIES UNDER AB 1X FOR MANAGING THE
ELECTRIC POWER FUND
After nearly two years, the department successfully completed
the sale of revenue bonds worth $11.26 billion to finance the
costs it incurred in its role as buyer of power for the State during
the power crisis. The proceeds from these bonds were used
to repay loans from the State’s General Fund of $6.1 billion
plus interest and to repay interim loans of $3.5 billion from
commercial sources. This financing includes a series of 31 bonds
with an annual debt service of approximately $900 million. The
final bond matures in May 2022, more than 20 years from the
beginning of the department’s power-buying responsibility.
As revenue bonds, the department’s bonds are supported by the
revenues received from customers of the three investor-owned
utilities. Under a rate agreement with the CPUC established in
February 2002 and associated servicing agreements with each of
the utilities, the department receives revenues needed to cover
power costs and repayment of the bonds through charges to
customers of the utilities. Two charges are set annually. Bond
charges are set to recover financing costs associated with the
bonds, and power charges are set to recover the annual cost of
power under the contracts. These revenue streams, secured by
a rate agreement with the CPUC regarding the procedures to be
followed to determine the amounts to charge ratepayers, ensure
that there will be sufficient cash to pay bondholders and were
necessary to secure more favorable ratings on the bonds to lower
the overall cost of the program.
Going forward, the
department will be Going forward, the department will be responsible for
responsible for ensuring ensuring that revenues are sufficient to cover the costs of the
that revenues are bonds for the life of the bonds and to cover the costs of the
sufficient to cover the power purchased under the power contracts for as long as the
costs of the bonds for department holds the contracts. Each year, the department
the life of the bonds and must determine the amount of revenue it needs to collect, and
to cover the costs of the it must submit that requirement to the CPUC. For 2003, the
power purchased under department has determined its revenue requirements to include
the power contracts for as $4.6 billion for the power it sells to the utilities’ retail customers
long as the department and revenues needed for debt service on bonds of nearly
holds the contracts. $1.2 billion. The department estimates its ongoing debt service
to be approximately $900 million per year through 2022.
112222 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112233
To carry out its financial responsibilities under AB 1X, the
department must ensure that its available cash is sufficient to
maintain its credit standing with its power suppliers and the
bondholders, and it must conduct the analysis and reporting
functions necessary to support that activity. The department
will be required to maintain the capability to carry out this
significant financial and reporting responsibility for the duration
of the bonds. As described in Chapter 1, the power charges
will remain significant through 2010 and will be substantially
reduced thereafter. The department will have regular reporting
requirements to the CPUC, bond investors, auditors, the
governor, and Legislature.
The return of power-purchasing authority to the utilities
carries with it a set of issues to be resolved in establishing the
methods of recovering revenue from the three utilities. As we
mentioned previously, in September 2002, the CPUC allocated
the department’s contracts among the three investor-owned
utilities for the purpose of power-procurement planning. This
was followed by a December 2002 interim order allocating
contract costs to the three utilities. A number of issues remain
to be resolved, including the equitable allocation of costs and
modification of servicing agreements, which state the terms and
conditions for various services, including billing and collection.
These issues illustrate the nature of the ongoing role that the
department will have in managing its revenue recovery process.
THE DEPARTMENT’S CONTRACT OPERATIONS
ARE TRANSFERRING TO THE UTILITIES, BUT
SIGNIFICANT COORDINATION AND MONITORING
RESPONSIBILITIES REMAIN
On December 31, 2002, the department’s AB 1X authority
to enter into new contracts to buy power came to an end.
Beginning January 1, 2003, that responsibility and function
returned to the three investor-owned utilities. In addition, while
the department remains financially and legally responsible
for the contracts, the investor-owned utilities, as agents of the
department, have assumed the dispatch and administrative
functions related to the portfolio.
112244 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112255
The Department’s Role in the Management of Contract
Operations Changes With the Transfer of Power Operations
to the Utilities
In conjunction with its role as power buyer for each of the
utilities in 2001 and 2002, the department also conducted
scheduling and dispatch functions in coordination with the
utilities. Through agreements with the CPUC and the utilities,
these scheduling and operating functions for the department’s
contract portfolio are being transferred to the utilities, at the
same time that the utilities are reassuming the scheduling and
dispatch functions for meeting their overall load responsibilities.
The department, the CPUC, and the utilities conducted
In September 2002, a negotiations and regulatory proceedings in 2002 to establish
CPUC order allocated the the regulatory and contractual framework for the transfer of
department’s contracts operating functions to the utilities. The September 2002 CPUC
to the three utilities, order allocating the department’s contracts among the three
establishing those utilities established those contracts for which each utility would
contracts for which each assume operating responsibility in 2003. Another order issued
utility would assume in October 2002 directed all three utilities to resume power
operating responsibility procurement responsibilities on January 1, 2003, and made
in 2003. provisions for the adoption of interim procurement plans that
would serve as the basis for the start of utility procurement
in 2003. In December 2002, the CPUC issued an operating
order that set forth the principles under which the utilities
would conduct operations, including the management of the
department’s contracts. The operating order was adopted in
lieu of formal operating agreements between the department
and each of the utilities, due to the time limits imposed by
the January 1, 2003, deadline for transition. The department
completed operating agreements with PG&E and SDG&E prior
to January 1, 2003, and the utilities filed these agreements
with the CPUC for approval. The department and the utilities
continue to work toward completion of formal, CPUC-approved
operating agreements.
Under the operating agreements between the department and each
utility, and under the operating order until agreements between
the department and each utility are completed, the utilities are
now serving as agents for the department regarding the day-to-day
operations, including dispatch and scheduling of the department’s
contracts. According to the department, functions that had
been conducted by it prior to January 1, 2003, that are now the
responsibility of the utilities, include the following:
112244 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112255
• Purchasing power to meet the daily net-short requirements.
• Forecasting the net-short requirements.
• Scheduling contracts for deliveries to meet the
Under the CPUC’s net-short requirements.
operating order, the
utilities are now serving • Purchasing of natural gas associated with department contracts.
as agents for the
• Interacting with the ISO on scheduling and settlements.
department regarding the
day-to-day operations,
The operating agreements provide a contractual basis for the
including dispatch
performance of these functions. As regulated entities, the
and scheduling of the
utilities’ participation in and performance under the operating
department’s contracts.
agreements, along with their other functions in procuring
power and providing it to their customers, is subject to
regulatory oversight by the CPUC. Thus, the department’s power
operations role is now indirect. The department must maintain
the capabilities to manage and oversee its contracts with the
utilities, but it no longer requires the capacity to perform those
operating functions directly.
Dispatch Optimization Remains an Important Issue for the
Department and California’s Ratepayers
In our December 2001 audit, and in Chapter 5 of this report, we
have noted the importance of and the need for close coordination
between the department and the investor-owned utilities in
power procurement and dispatch operations to assure that the
department’s contracts and the utilities resources are coordinated
to minimize costs to consumers. This issue will remain important
in the years ahead and has been recognized by the Legislature, the
CPUC, the department, and the utilities in structuring the transfer
of operating responsibility back to the utilities.
AB 57 makes clear the Legislature’s intent that “. . . each electrical
corporation optimizes the value of its overall supply portfolio,
including Department of Water Resources contracts and
procurement . . . for the benefit of its bundled service customers.”
In its December 2002 order regarding the operating agreements,
the CPUC espouses this same principle, stating, “Least-cost
or ‘economic’ dispatch should be the operating rule for the
utility’s portfolio of resources, including the DWR [department]
contracts.” It has reflected that same principle in the operating
protocols included in that order. The operating agreements that
the department has negotiated with PG&E and SDG&E contain
the following language in the operating protocols:
112266 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112277
“Utility agrees to use good faith efforts to dispatch
Allocated Contracts and, prior to novation, Interim
Contracts, based on the principle of “least cost dispatch”
to retail customers, consistent with the Contract Allocation
Order and other Applicable Commission Orders. Utility
shall undertake these least cost dispatch functions both of
the Contracts and its URG [utility-retained generation] so
as to minimize the cost of service to retail customers based
on circumstances known or that reasonably could have
been known at the time dispatch decisions are made. DWR
shall have no role in enforcement or review of Utility least
cost dispatch under this Agreement and all issues of Utility
compliance with least cost dispatch shall be within the
sole review of the Commission.”
This statutory, regulatory, and contractual construct makes
clear the responsibilities of the utilities in conducting the
operations in a least-cost manner. As of this writing, the
role of the CPUC in overseeing the utilities’ performance
in that regard is being contested by the utilities, leaving
unresolved the precise nature of the utilities’ accountability in
implementing this operating principle.
Optimizing the dispatch across the three investor-owned
utilities for the benefit of customers may remain a challenge.
Based on our Consolidating resources in the hands of the utilities creates an
consultant’s review of opportunity for them to coordinate the dispatch of their own
past coordination issues supplies and their allocated department contracts more easily
between the department than they could if (as was the case in 2002) the department
and the utilities, the contracts and the utility generation sources are each dispatched
ratepayer savings with by separate entities. The CPUC recently stated that “the best way
fully coordinated dispatch to coordinate DWR’s existing contracts with utility resources
are potentially on the is to put them all in the utilities’ resource portfolios to be
order of tens of millions scheduled and dispatched in a least-cost manner.” However,
of dollars annually. this allocation to the utilities does end the single, statewide
dispatch that was being conducted by the department, breaking
the contract portfolio into three parts. The department has
worked to establish operating agreements with the utilities that
would, to the extent possible, standardize operating procedures
and limit the utilities’ ability to manipulate the dispatch of
generating facilities to maximize their own revenues while
increasing department costs and, ultimately, ratepayers’ bills.
Implementing least-cost dispatch is an important and difficult
challenge in practice. Based on our consultant’s review of
past coordination issues between the department and the
112266 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112277
utilities, the potential ratepayer savings with fully coordinated
dispatch are on the order of tens of millions of dollars annually.
However, the dispatch operations process is complex to audit
and could be very difficult to police. The situation is not unlike
the challenge of monitoring wholesale power markets for
inappropriate pricing practices, where the sheer volume and
complexity of the relevant data can make monitoring behavior
and detecting problems extremely challenging. As such, a failure
to establish, prospectively, data retention requirements, data
sharing protocols, monitoring mechanisms, and evaluation
standards would be problematic. Ensuring that the department’s
future contract costs are consistent with those of a least-cost
dispatch requires that the principles articulated in the operating
agreements be effectively implemented in practice.
The Potential for Sales of Surplus Power Is Increasing
As shown in Figure 16, the department’s projections of the future
sales of surplus power indicate a substantial increase in the
potential for sales over the 2002 levels described in Chapter 4.
Total dispatchable and nondispatchable contract supplies in
2003 will be more than 50 percent above 2002 levels and will
remain high for several more years. As the figure indicates, the
department’s projected sales of power from its long-term contracts
is expected to peak in 2004 at well above 14,000 gigawatt-hours.
While the department’s forecast is derived from an analysis of
the total load of the three utilities, the surplus sales potential for
each of the individual utilities may be larger, as the three systems
will be operated individually rather than under a single dispatch
conducted by the department.
This significant potential for surplus power received considerable
attention in recent CPUC proceedings. In its September 2002
order allocating the department’s contracts to individual
utilities, the CPUC established a proportionate sharing policy for
the allocation of revenues gained or losses incurred from such
sales, recognizing that there would otherwise be an incentive for
the utilities to attribute a disproportionate share of the surplus
sales to department contracts. This proportionate sharing
principle is included in the operating order and in the operating
agreements executed with PG&E and SDG&E.
112288 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112299
FIGURE 16
Projected Off-System Sales of Excess Contract Energy
������
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�����
�����
�����
�
���� ���� ���� ���� ���� ���� ���� ���� ���� ����
Source: Power Supply Revenue Bonds, Department of Water Resources, consultant report, October 2002, prepared by
Navigant Consulting, Inc.
The operating agreements include requirements that the utilities
provide monthly sales plans and provide information necessary
for the department to assess the utility’s activities. Due to the
The cost of natural gas is detailed nature of the information needed to assess the sales
the single most significant activity, the department will be required to maintain an active
component of the cost capability to monitor this activity and the impacts on its revenue.
of electricity, and it is
increasing in volume as
Substantial Challenges Are Looming in Relation to
the contracts operating
Gas Procurement
in the department’s
portfolio increase in the The department’s gas tolling agreements will be of increasing
coming years. importance to the department and California ratepayers. The
cost of natural gas is the single most significant component
of the cost of electricity, and it is increasing in volume as the
contracts operating in the department’s portfolio increase in the
coming years. The gas costs for the five contracts containing
112288 California State Auditor Report 2002-009 California State Auditor Report 2002-009 112299
��������������
the most significant gas tolling opportunities (that is, those
where the department has gas purchase rights, including
Dynegy, Calpine, Sunrise, PacifiCorp, and High Desert),
based on total projected gas volumes of nearly 250 million
MMBtu for the year, could exceed $1 billion in 2003. As
we note in Appendix B, the department’s contract capacity
from agreements with gas tolling in 2003 will be nearly
8,000 megawatts, almost double the 2002 levels.
The generators selling electricity to the department on fuel pass-
through agreements do not appear to have strong contractual
incentives to minimize their fuel costs; they will simply pass
those costs on to the department in the electricity sales price.
For example, in 2003 if fuel costs were to escalate by as little
as 25 cents per MMBtu due to poor gas cost management
practices, $62.5 million in additional costs would accrue to the
department and California ratepayers over the course of the
year if the CPUC failed to identify the problem during one of
its reviews. The department’s experience to date indicates that
its active involvement, or such involvement by the utilities as
its agents in 2003, will be important to ensure that gas costs are
properly minimized.
Under the operating agreements with the utilities, the utilities
will operate as agents for the department in administering
the fuel procurement associated with the tolling agreements.
The utilities will prepare annual gas supply plans, subject
to department and CPUC review, and will conduct the gas
procurement and risk management activities called for in these
plans. Issues that will need to be resolved as the utilities assume
this responsibility include the approach to hedging and the
The generators selling process for developing and reviewing gas supply plans. The
electricity to the transition has also proved challenging, as gas supply plans for
department on fuel the first few months of 2003 were not in place.
pass-through agreements
do not appear to have Credit and collateral issues will also be important. The ability to
strong contractual lock in low gas prices may be hampered by credit problems of
incentives to minimize the utilities and of the sellers under department contracts. For
their fuel costs; they will example, even after the department’s retail revenue stream was
pass those costs on to established and it had achieved a payment history, its ability to
the department in the make forward purchases of gas was constrained by credit limits.
electricity sales price. By contrast, Dynegy’s current credit situation is more difficult.
Dynegy is likely to have to pay a premium to make forward
purchases, and thus the department is buying gas for that
contract. If gas procurement is left to Dynegy, it can be expected
113300 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113311
to purchase the gas on the daily spot market. Similarly, credit
concerns could limit the ability of the California utilities to
purchase gas on a forward basis, particularly in the near term.
THE DEPARTMENT IS STILL DEVELOPING THE ABILITY
TO VALIDATE REVENUE REMITTANCES FROM THE
INVESTOR-OWNED UTILITIES
In our December 2001 audit, we reported that the department
needed to implement a process to ensure that it receives all of
the revenue it is due from the electric power it purchases for the
retail customers of the investor-owned utilities. The department
responded that it was developing a system to track the electric
power delivered to the investor-owned utilities’ retail customers
and to reconcile that power to the revenues the investor-owned
utilities remit to the department, to ensure that it receives all
amounts it is owed. Although the department has developed
a tool to estimate amounts owed to it by the investor-owned
utilities, due to the many variables involved in identifying
revenues owed to the department, it is still working with the
utilities to develop a mutually satisfactory methodology for
calculating revenue remittances on a current month basis. As
a result, the department cannot yet validate that the daily and
monthly remittances it receives account for all of the revenue it
For calendar year 2003, is due from two investor-owned utilities, and for the third utility
the department expects it must wait six months for a final reconciliation of revenues
to collect approximately based on estimated versus actual power delivered. These delayed
$4.6 billion for the collections can cause cash-flow problems for the department’s
power it sells to the operations by mismatching revenues and expenditures and
investor-owned utilities’ increasing the probability that any revenues that have not
retail customers. been remitted will not be detected. For calendar year 2003, the
department expects to collect approximately $4.6 billion for the
power it sells to the investor-owned utilities’ retail customers.
According to the department, developing a process for validating
the revenues remitted by the investor-owned utilities on a
regular and current basis has been a challenge—complicated by
the indirect relationship among department power deliveries,
amounts utilities bill on behalf of the department, and the way
that utilities report remittances; changes in the charges the
investor-owned utilities must collect for the department; and,
most recently, the investor-owned utilities’ resumption of the
responsibility for purchasing the net short.
113300 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113311
To validate that it receives all of the revenues it is owed on
a timely basis, the department has determined that it must
reconcile the amount of power it purchases to the amount
of power that the investor-owned utilities bill to their retail
customers. Next, the department has determined that it needs to
reconcile the amounts the investor-owned utilities bill to their
retail customers for the delivered power to the amounts that the
utilities remit to the department. According to the department,
it is currently in the final stages of developing a methodology to
validate the revenues and is working with one utility, SDG&E,
to fine-tune this methodology. The purpose of this methodology
is to provide a satisfactory level of comfort that the department
receives the revenues it is due and that the utility does not
overpay the department. Once the department has developed
a satisfactory model, it plans to apply it, with variations, to the
other two investor-owned utilities to ensure that remittances
are received in a timely manner. This methodology will use
acceptable assumptions and margins of error for estimates
that are necessary due to the varied billing cycles the investor-
owned utilities use in connection with electric power sales—
compounded by the timing of the collections of those bills.
According to the department, these factors make the absolute
validation of the revenues administratively infeasible, at times
requiring the department to measure the reasonableness of the
remittances, using acceptable margins of error when comparing
power purchased to revenues received.
Currently, the department relies on power transaction
settlement information from the ISO and information provided
by the investor-owned utilities to determine the amount of
power delivered to the utilities’ retail customers, and it performs
periodic analyses in an attempt to verify that it receives all
the revenue it is due. For example, during a 2002 year-end
remittance validation process, the department completed a
preliminary remittance analysis that revealed some discrepancies
between the amount of department power delivered to the
utilities’ retail customers and the amount of department
power for which the utilities billed their customers. These
discrepancies could be the result of factors such as delays in
billing department revenues, possibly due to certain customers
receiving delayed utility bills or normal utility billing errors
that will likely be corrected in the future. The department states
that it has met with the investor-owned utilities to discuss the
discrepancies and to begin quantifying the impact of certain
types of billing deviations.
113322 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113333
In addition, the validation of remittances has been complicated
by associated factors, such as retroactive department power rates
established by the CPUC and orders from the CPUC that require
the utilities to remit revenues associated with the department’s
imbalance power purchases and to collect department bond
charges and fees from retail customers who elect to purchase
their electric power from sources other than the three investor-
owned utilities affected by the power-purchasing program.
These orders have created substantial changes in the amount
of revenue the utilities owe the department for delivered
power. For example, analyses the department conducted in
September 2002 of the effect of these orders resulted in two
additional remittances from the investor-owned utilities of
about $198 million and $873 million.
According to the department, it will need to make extensive
changes in its revenue validation processes in 2003 to
According to the accommodate changes that the CPUC has ordered in the power
department, it will charge calculations. The department began collecting bond
need to make extensive charges from utility customers in November 2002 and is currently
changes in its revenue developing processes to validate these remittances. In addition,
validation processes in in January 2003 the department began to receive power charges
2003 to accommodate from direct access customers, and it expects to receive remittances
changes that the CPUC for bond charges from direct access customers later this year.
has ordered to the power The development of new remittance validations for all of these
charge calculations. collections is dependent on the department receiving additional
information from the investor-owned utilities and on a clear
interpretation by the department and the investor-owned utilities
of the methods approved by the CPUC.
Finally, as of December 31, 2002, the department no longer
purchases the residual net short for the investor-owned utilities.
Because it is no longer a market participant, the department may
not receive data directly from the ISO regarding the power used
to satisfy the residual net short and delivered to utility customers.
The department is currently working with the investor-owned
utilities to secure the data it needs to validate power and bond
charges. In the near future, this will result in additional changes
in the methodology it uses to validate revenue remittances
and additional challenges in reconciling the amount of power
the department delivers to the utilities’ retail customers to the
amount of department power billed to those customers.
113322 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113333
RECOMMENDATIONS
The department’s future activities can be described as falling
into four broad categories, each defined by basic contractual
responsibilities that it will carry into the future. If the
department is to successfully complete its remaining mission
under AB 1X, it will need to do the following:
Management of Long-Term Contracts
• Monitor the performance of power suppliers relative to their
contractual obligations.
• Promptly address and resolve any supplier deviations from
contractual obligations.
• Persistently and aggressively manage the long-term contracts
to capture opportunities to improve the overall supply portfolio.
Management of Operating Agreements With the Investor-
Owned Utilities
• Recognizing the CPUC’s established role in overseeing
the dispatch decisions of the investor-owned utilities, the
department should routinely monitor resource scheduling
and other data provide by each utility to ensure that dispatch
decisions are consistent with established operating protocols
and its fiduciary responsibility to bondholders.
• Routinely collect and analyze data (including ISO settlement
data) on power sales by the investor-owned utilities.
• Address proposed annual gas supply plans for contracts with
tolling agreements. Respond to situations in which the credit
standing of the investor-owned utilities may adversely affect
the department’s costs.
• Maintain capabilities to analyze conditions in electricity and
gas markets.
• Advise the CPUC in a range of proceedings in which its
regulatory oversight of the investor-owned utilities intersects
with the department’s responsibilities.
113344 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113355
Management of Servicing Agreements With the Investor-
Owned Utilities
• Monitor dispatch statements from the investor-owned utilities
relative to their accounting statements to the department.
• Advise the CPUC in proceedings in which its regulatory
oversight of the investor-owned utilities intersects with the
department’s responsibilities.
Servicing the Revenue Bonds
• Prepare revenue requirements filings for the CPUC. Advise the
CPUC in revenue requirements proceedings (and others) in
which its regulatory oversight of the investor-owned utilities
intersects with the department’s responsibilities under the
revenue bonds.
• Act to mitigate risks that may adversely affect bondholders.
Address CPUC ratemaking practices that may create incentives
for the investor-owned utilities to act in a manner contrary to
the interests of the department’s bondholders or to its mission
under AB 1X.
• Perform financial and accounting activities necessary to support
the department’s obligations (including fulfilling reporting
requirements to bond investors, auditors, rating agencies, the
governor, and the Legislature) under the revenue bonds.
113344 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113355
We conducted this review under the authority vested in the California State Auditor by
Section 8543 et seq. of the California Government Code and according to generally accepted
government auditing standards. We limited our review to those areas specified in the audit
scope section of this report.
Respectfully submitted,
ELAINE M. HOWLE
State Auditor
Date: April 2, 2003
Executive Staff: Philip J. Jelicich, CPA, Deputy State Auditor
Sharon Reilly, Esq., Chief Legal Counsel
Staff: John Baier, CPA, Project Manager
Norm Calloway, CPA
Michael K. Adjemian
Consultant: La Capra Associates
113366 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113377
APPENDIX A
A Summary of the Department’s
Progress Toward Implementing the
December 2001 Recommendations of
the Bureau of State Audits
The Bureau of State Audits (bureau) made a variety of
recommendations to the Department of Water Resources
(department) in its December 2001 audit titled, California
Energy Markets: Pressures Have Eased, but Cost Risks Remain
(report number 2001-109). The table in this appendix shows the
bureau’s recommendations and the department’s progress in
implementing those recommendations.
TABLE A.1
Bureau Recommendations and the Department’s Actions Since the December 2001 Audit
Recommendations Department’s Actions
The power-purchasing program was conceived during an
unprecedented crisis. The crisis has abated to a large degree,
and the State and the department now need to reassess with
a longer-term perspective the goals of this power-purchasing
program and the program’s implementation. At this juncture,
in view of the evolving creditworthiness of the investor-owned
utilities and the emerging role of the power authority, the
Legislature and the governor should consider the following actions:
• Develop a comprehensive, long-term strategic framework • The governor and the Legislature have taken some
for the electricity industry in the State and for the actions on this recommendation, but have not crafted a
department’s role in that system. comprehensive, long-term strategic framework for the
State’s electricity industry.
• Establish an appropriate statutory framework, including the • The transition of the power-purchasing role from the
possible amendment of AB 1X, to extend the department’s department to the investor-owned utilities occurred
purchasing authority in order to allow adequate time on January 1, 2003. As discussed in Chapter 6, certain
to implement the strategic framework, to afford more challenges continue for the department in the post-
flexibility in the termination of the department’s purchasing transition period.
authority, and to assure continuity of the purchasing
function and an effective transition for this function,
presumably to the investor-owned utilities.
In the context of the evolving state policy on the future of the
industry and the power-purchasing program, the department
should take these steps:
• Create a strategic plan for the future of the power- • Effective January 1, 2003, the responsibility for purchasing
purchasing program at the department, including the the net short returned to the investor-owned utilities. As
assessment of the transition processes needed to allow such, the department has a limited future role in the power
orderly transfer of functions to the ISO, the investor-owned market. (See Chapter 6 for a discussion of the department’s
utilities, and others, as appropriate. forward-looking issues.)
continued on next page
113366 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113377
Recommendations Department’s Actions
• Continue efforts to coordinate the responsibilities of • Effective January 1, 2003, the department’s authority to
the department with respect to the Power Authority to enter into contracts or purchase power outside its existing
establish clearly the roles and responsibilities of each contracts expired. Given such a limited role, the roles and
organization. responsibilities of the Power Authority with respect to those
of the department are irrelevant.
With the substantial long-term contract portfolio in hand, the
department needs an aggressive cost and risk management
program. Actions taken or initiatives underway include the
following:
• Energy Transacting and Risk Management (ETRM)
System—a database system designed as a decision support
and management tool to support portfolio management,
risk assessment, and pricing analysis for transactions and
contracts. The system is scheduled for implementation in
two phases during the first two quarters of 2002, and it is
designed to address market risk, financial risk, and credit risk.
• Contract Management Protocol—an organizational
structure and set of business processes being implemented
in fall 2001 designed to conduct the contract management
function related to the power-purchasing program.
In doing so, the department should also take these steps:
• Conduct within 90 days, in conjunction with the legal • In September 2002, the CPUC allocated the department’s
review noted below, an in-depth economic assessment power contracts to the investor-owned utilities to facilitate
of the contracts and the overall supply portfolio serving the transition to the utilities of purchasing the net short. As
the investor-owned utilities’ customers to ensure that such, the utilities will manage the department’s contracts,
the department can develop an effective overall contract and the associated risks, along with their power resources
management strategy. This assessment should focus on in providing electric power to their retail customers.
how the contracts fit into the overall portfolio and on the
costs relative to current expectations of market conditions.
• Develop a contract renegotiation strategy, informed by the • During 2002, the department renegotiated 23 of its larger
legal and economic reviews, that focuses on improving the contracts in an attempt to improve the amount and prices
reliability and overall performance of the portfolio. of the power and the terms of the contracts. We discuss
the amount of power under the renegotiated contracts
in Chapter 1, the costs in Chapter 2, and the terms in
Chapter 3.
• Ensure that the contract management plan addresses the • See the previous comments.
department’s obligations under the contracts both before
and after the in-service dates.
• Consider staffing approaches, including further consultants • Effective January 1, 2003, the investor-owned utilities
and contractors if needed, to ensure that personnel resumed responsibility for purchasing the net short. As a
shortages do not continue to hinder the development and result, the department indicates that it is re-aligning its
implementation of these systems. organization and reducing its staff to meet its reduced
responsibilities.
• Establish a planning process that more directly integrates • Effective January 1, 2003, the investor-owned utilities
the entire portfolio of supplies serving customers of the resumed the responsibility of purchasing the net short and
investor-owned utilities with the role of the department’s the CPUC allocated the department’s power contracts to
contracts in that portfolio. As specified in AB 1X, this the utilities. As a result, the utilities will be responsible for
process should include consultation with the CPUC and integrating the department’s contracts into their portfolios
with the investor-owned utilities. and dispatching their power resources in a least-cost
manner for their retail customers under the regulation of
the CPUC.
113388 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113399
Recommendations Department’s Actions
The department now holds many long-term power contracts
that have many “seller-friendly” provisions that represent
important legal risks to the department. Further, it is
reasonable to assume that with a long-term contract portfolio
of this size and complexity, the department will have some
litigation with the generators concerning the interpretation of
the terms and conditions of the contracts. In this context, the
department should do the following:
• Conduct in-depth assessments of legal risk and legal • During 2002, the department renegotiated 23 of its
services requirements within 90 days to assure that the contracts, which generally resulted in much stronger
department can develop an effective legal management guarantees that sellers will deliver the power promised
strategy, including an effective “swords and shields” plan. under the contracts and build the new generation
promised in the contracts. See Chapter 3 for a full
discussion of the terms of the renegotiated contracts.
• Establish an ongoing legal services function that specializes • To examine the contracts and set goals for renegotiation
in power contract management, negotiation, and litigation and to renegotiate the contracts, the department
to assure that the department’s legal assessment and assembled a team comprised of the department’s legal
representation is on par with those of the other parties and technical consultants as well as representatives from
participating in the contracts. When necessary to avoid the attorney general’s office, the CPUC, and the governor’s
conflicts, this legal function should be separate and distinct office.
from counsel retained to sell bonds or to provide legal
advice to the State Water Project.
• Investigate all audit and other rights available to the • See the previous comments.
department under its contracts to assure that it can
develop a proper performance enforcement program.
Department actions taken or initiatives underway to improve
its short-term transactions functions include the following:
• Power Scheduling and Settlements System—a system
designed to support the power scheduling and ISO
settlement functions. Scheduled for implementation in the
fourth quarter of 2001.
• ETRM System—this system provides support for short-term
trading and management as well as for the longer-term
portfolio management discussed above.
These actions are obviously important, and the department
should implement them as soon as possible. In doing so, the
department should take these actions:
• Clarify and resolve settlement process problems associated • In November 2001, the Federal Energy Regulatory
with the energy and ancillary services functions that the Commission ordered the ISO to stop relying on the
department has been and continues to conduct on behalf department to make imbalance and ancillary services
of the ISO. transactions on behalf of the ISO.
• Conduct an assessment of the imbalance energy sales and • The department’s sales of surplus power have not had a
purchase volumes to determine whether they are significantly significant effect on the costs of the power-purchasing
increasing the department’s net power costs. If so, the program. (See Chapter 4 for a full discussion of the
department should develop plans to mitigate those costs. department’s sales of surplus power.)
• Enhance the organization’s skills for market analysis and • Effective January 1, 2003, the investor-owned utilities
contract management to properly address the implications of resumed responsibility for purchasing the net short. As a
uncertainty on portfolio management and dispatch decisions. result, the department indicates that it is re-aligning its
organization and reducing its staff to meet its reduced
responsibilities.
continued on next page
113388 California State Auditor Report 2002-009 California State Auditor Report 2002-009 113399
Recommendations Department’s Actions
• Fully staff the power-purchasing program. Although the • See the previous comments.
program’s organization has come a long way, it lacks
adequate staff to match the magnitude of its trading and
related activities (for example, planning, settlement, and
fuel management). The planning and operational duties
will also increase in the coming months as a significant
amount of dispatchable long-term contracts take effect.
• Develop a transition plan for the orderly transfer of the • The department has worked with the investor-owned
short-term purchasing and net short management functions utilities and the CPUC to transfer the purchasing of the net
at the conclusion of the AB 1X purchasing authority. short to the utilities, effective January 1, 2003.
• Consider staffing approaches, including further consultants • Effective January 1, 2003, the investor-owned utilities
and contractors if needed, to assure that personnel shortages resumed responsibility for purchasing the net short. As a
do not continue to hinder these operations over the next result, the department indicates that it is re-aligning its
year and to provide for an effective transfer of the purchasing organization and reducing its staff to meet its reduced
functions at the conclusion of the AB 1X authority. responsibilities.
The department should take the following actions to improve
its capabilities to effectively coordinate with the utility-retained
generation to minimize the total costs of serving the customers
of the investor-owned utilities:
• Collaborate with the investor-owned utilities to share • Coordinated dispatch of power resources to produce
information about their respective generation sources a least-cost dispatch of power to retail customers is an
and to organize a least-cost dispatch of those sources. element of the operating order the CPUC placed on the
The investor-owned utilities also need to commit to this investor-owned utilities. As the State’s utility regulatory
effort and to plan for ongoing coordination when the agency, the CPUC will enforce its orders through annual
investor-owned utilities reassume the net-short purchasing procurement reviews of the utilities. (See Chapter 5 for a
authority, including coordination of dispatch with the discussion of coordinated dispatch.)
department contracts.
• Coordinate with the investor-owned utilities to ensure that the • See the previous comments.
collective supply sources operate in a manner that minimizes
the total cost of providing energy and ancillary services.
• Work with the investor-owned utilities and the CPUC to • See the previous comments.
ensure that the rate incentives associated with utility-
retained generation scheduling are resolved to support a
least-cost dispatch.
To improve its ability to carry out the full functions of a power-
purchasing program of this scale, the department should take
these actions:
• In its future efforts to protect the interests of the power- • In light of its reduced role in the California power
purchasing program, the department should retain market, the department indicates that it is realigning
independent legal counsel to advise the department on its organization and staffing levels, including legal and
matters pertaining to state and federal regulatory issues technical consultants, to support its post-January 1, 2003,
affecting the power-purchasing program when those responsibilities.
interests conflict with the interests of the State Water Project.
• Conduct a comprehensive assessment of the department’s • Effective January 1, 2003, the investor-owned utilities have
collaboration with the attorney general, the Energy Oversight resumed responsibility for purchasing the net short. The
Board, the CPUC, and other state entities to assure that the department has been active in CPUC proceedings to shape
interests of the power-purchasing program are distinctly and its future role.
adequately represented in regulatory proceedings.
• Seek clear statutory authority to use financial instruments • In December 2001, the attorney general provided
to manage gas and electric transaction risks. the department with an opinion indicating that the
department has the legal authority to engage in
transactions to hedge gas supply prices.
114400 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114411
Recommendations Department’s Actions
To improve its ability to monitor the investor-owned utilities’
performance in complying with the terms of the servicing
agreements, the department should do the following:
• Amend the servicing agreements to include language • Because as of January 1, 2003, the department no longer
that promotes accuracy in estimates of customer usage purchases the net short on behalf of the investor-owned
provided by the investor-owned utilities. utilities, it no longer needs estimates of customer power
usage.
• Complete its efforts to ensure that it can account for all • The department is conducting an ongoing effort to identify
of the amounts it is owed by the investor-owned utilities, a methodology to ensure that it receives all of the revenue
including the completion of its project to track power it is due from the sale of the power it purchases for the
delivered to retail customers. retail customers of the investor-owned utilities. The task
has been challenging due to changes in the rates to retail
customers and also due to utilities’ collections of direct
access fees from retail customers and the department’s
revenue requirements to repay its bonds.
• Develop audit procedures to review periodically the • The CPUC ordered the investor-owned utilities to enter into
investor-owned utilities’ performance of critical elements servicing agreements with the department. As the State’s
in the servicing agreements, such as cash remittance utility regulatory agency, the CPUC will enforce these
methodologies, the allocation to customers of the orders with the utilities.
investor-owned utilities of the power that the department
purchases, and the cost of energy conservation programs.
• Coordinate with the investor-owned utilities to develop • Although the department agrees that audit procedures
audit procedures designed to detect noncompliance with will help it monitor the utilities’ compliance with
the critical elements of the servicing agreements. These certain requirements of the servicing agreements, due
procedures can be performed by the investor-owned to competing priorities, it has not yet developed such
utilities’ certified public accountants in conjunction with procedures.
annual financial audits.
• Complete its efforts to execute agreements with the • Because effective January 1, 2003, the department no
three investor-owned utilities that cover power purchases longer purchases the net short on behalf of the investor-
designed to balance in real time the electrical power owned utilities, it no longer needs agreements with the
supplied to the power grid with total customer usage. utilities to cover real-time purchases of power to cover the
net short.
To help ensure that its contractors do not have conflicts of
interest, the department should continue its efforts to review
all employees and consultants twice each year and it should
retain a record of its review for each review period.
The department implemented new procedures to ensure
that all department employees and contractor employees are
screened for the requirement to disclose financial interests
that may represent a conflict of interest. We found that the
department substantially complies with its new procedures.
The department should improve its controls designed to have
all power-purchasing program costs appropriately charged to
the program and supported by evidence of service.
Although we found immaterial errors, the department has
taken adequate steps to ensure that all power-purchasing
program costs are appropriately charged to the Electric
Power Fund.
114400 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114411
Blank page inserted for reproduction purposes only.
114422 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114433
APPENDIX B
Detailed Tables to Support Summary
Data Shown in Chapter 1
Tables 2, 5, and 6 in Chapter 1 display the results
of our analysis of the capacity distribution in the
contract portfolio before and after the State’s contract
restructuring activities during 2002. These three summary
tables show the net change in capacity before and after
the contract renegotiations, and we use them to show the
improved fit of the contract portfolio to consumer demand after
renegotiation. To place those summary tables in perspective, this
appendix presents three detailed tables, B.1, B.2, and B.3, to show
the total capacity amounts involved, measured in megawatts. The
headings of each detailed table correspond to the headings of the
summary table from Chapter 1 and also indicate the page number
where the summary table can be found.
114422 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114433
TABLE B.1
Change in Capacity Supplied by Long-Term Contracts*
(in Megawatts)
Calendar Year
Capacity Type 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Original Portfolio
Dispatchable 704 2,829 3,444 3,544 2,319 3,169 3,169 3,169 3,169 2,869
Nondispatchable 5,032 5,646 8,011 8,920 8,270 7,358 7,340 7,040 7,040 7,040
Total for all contracts 5,736 8,475 11,455 12,464 10,589 10,527 10,509 10,209 10,209 9,909
Dispatchable 12% 33% 30% 28% 22% 30% 30% 31% 31% 29%
Nondispatchable 88 67 70 72 78 70 70 69 69 71
Total for all contracts 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Renegotiated Portfolio
Dispatchable 846 3,721 6,069 5,314 4,314 4,089 4,089 3,959 3,959 3,959
Nondispatchable 4,867 6,008 7,193 7,602 6,802 6,653 6,650 5,975 5,975 3,675
Total for all contracts 5,713 9,729 13,262 12,916 11,116 10,742 10,739 9,934 9,934 7,634
Dispatchable 15% 38% 46% 41% 39% 38% 38% 40% 40% 52%
Nondispatchable 85 62 54 59 61 62 62 60 60 48
Total for all contracts 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Net Change
Dispatchable 142 892 2,625 1,770 1,995 920 920 790 790 1,090
Nondispatchable (165) 362 (818) (1,318) (1,468) (705) (690) (1,065) (1,065) (3,365)
Total for all contracts (23) 1,254 1,807 452 527 215 230 (275) (275) (2,275)
Source: Analysis by La Capra Associates using contract summary data from the Department of Water Resources. Capacities are for
peak periods for July and August.
*Summary table found on page 25.
114444 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114455
TABLE B.2
Change in Allocation of Contract Capacity Among Zones*
(in Megawatts)
Calendar Year
Zone 2001 2002 2003 2004 2005 2006–2010
Original Portfolio
NP15 1,945 3,638 3,893 4,218 3,993 3,915
SP15 3,791 4,837 7,562 8,246 6,596 6,416
Totals 5,736 8,475 11,455 12,464 10,589 10,331
NP15 34% 43% 34% 34% 38% 38%
SP15 66 57 66 66 62 62
Total for all contracts 100% 100% 100% 100% 100% 100%
Renegotiated Portfolio
NP15 1,730 4,965 5,033 4,103 4,103 3,426
SP15 3,983 4,764 8,229 8,813 7,013 6,430
Totals 5,713 9,729 13,262 12,916 11,116 9,856
NP15 30% 51% 38% 32% 37% 35%
SP15 70 49 62 68 63 65
Total for all contracts 100% 100% 100% 100% 100% 100%
Net Change
NP15 (215) 1,327 1,140 (115) 110 (489)
SP15 192 (73) 667 567 417 14
Total for all contracts (23) 1,254 1,807 452 527 (475)
Source: Analysis by La Capra Associates using contract summary data from the Department of Water Resources.
Note: Capacities are for peak periods for July and August.
*Summary table found on page 35.
114444 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114455
TABLE B.3
Change in Capacity of Tolling and Indexed Price Contracts*
(in Megawatts)
Calendar Year
Contract Type 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Original portfolio
Tolling and indexed 3,039 3,079 4,999 5,649 3,724 4,574 4,574 4,274 4,274 3,974
price†
Fixed prices 2,697 5,396 6,456 6,815 6,865 5,953 5,935 5,935 5,935 5,935
Total for all contracts 5,736 8,475 11,455 12,464 10,589 10,527 10,509 10,209 10,209 9,909
Tolling and indexed price 53% 36% 44% 45% 35% 43% 44% 42% 42% 40%
Fixed prices 47 64 56 55 65 57 56 58 58 60
Total for all contracts 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Renegotiated portfolio
Tolling and indexed price 3,271 4,221 7,919 7,714 6,214 6,839 6,839 6,409 6,409 6,109
Fixed prices 2,442 5,508 5,343 5,202 4,902 3,903 3,900 3,525 3,525 1,525
Total for all contracts 5,713 9,729 13,262 12,916 11,116 10,742 10,739 9,934 9,934 7,634
Tolling and indexed price 57% 43% 60% 60% 56% 64% 64% 65% 65% 80%
Fixed prices 43 57 40 40 44 36 36 35 35 20
Total for all contracts 100% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Net change
Tolling and indexed price 232 1,142 2,920 2,065 2,490 2,265 2,265 2,135 2,135 2,135
Fixed prices (255) 112 (1,113) (1,613) (1,963) (2,050) (2,035) (2,410) (2,410) (4,410)
Total for all contracts (23) 1,254 1,807 452 527 215 230 (275) (275) (2,275)
Source: Analysis by La Capra Associates using contract summary data from the Department of Water Resources.
Note: Capacities are for peak periods for July and August.
*Summary table found on page 37.
†Power-purchase contracts containing an indexed variable fuel cost component or provides an opportunity for the buyer to
purchase fuel.
114466 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114477
APPENDIX C
Detailed Report Card of Terms
Revised Through Renegotiations for
Those Contracts Reviewed in Our
December 2001 Audit
In Chapter 3 we discuss the progress made by the Department
of Water Resources (department) in restructuring the legal
terms and conditions of certain contracts in the portfolio.
We also present a summary report card table (Table 14 on
pages 72 and 73) that summarizes the changes in the legal terms
that we identified as being necessary to protect the department’s
interests and to ensure that suppliers abide by the contractual
agreements. In this appendix, we present the same report card
table on the following pages with the changes outlined by each
of the renegotiated contracts that were included in the report
card analysis of our December 2001 audit. The shading in the
table indicates contracts that we found to have a deficient term
during our December 2001 audit, and an “X” indicates that a
term was changed when the contract was renegotiated.
114466 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114477
114488 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114499
1.C
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114488 California State Auditor Report 2002-009 California State Auditor Report 2002-009 114499
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Blank page inserted for reproduction purposes only.
115500 California State Auditor Report 2002-009 California State Auditor Report 2002-009 115511
Agency’s comments provided as text only.
Department of Water Resources
1416 Ninth Street, Suite 1311
Sacramento, CA 95814
To: Elaine M. Howle, State Auditor
Bureau of State Audits
555 Capitol Mall, Suite 300
Sacramento, California 95814
From: Mary D. Nichols (Signed by: Mary D. Nichols)
Secretary for Resources
Subject: Department of Water Resources’ Response to the Bureau of State Audit’s Draft Report
Enclosed is the Department of Water Resources’ response to the Bureau of State Audit’s
draft report entitled “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, April 2003.”
If your staff has any questions, please call Peter Garris, Deputy Director of the California
Energy Resources Scheduling Division, Department of Water Resources at (916) 574-2733.
Enclosure
115500 California State Auditor Report 2002-009 California State Auditor Report 2002-009 115511
M e m o r a n d u m
Date: March 20, 2003
To: Honorable Mary D. Nichols
Secretary for Resources
The Resources Agency
1416 Ninth Street, Room 1311
Sacramento, California 95814
From: Department of Water Resources
Subject: Department of Water Resources’ Response to the Bureau of State Audit’s Draft Report
The Department of Water Resources has reviewed the draft report entitled : “California
Energy Markets: The State’s Position Has Improved, Due to Efforts by the Depart-
ment of Water Resources and Other Factors, but Cost Issues and Legal Challenges
Continue, April 2003”. We appreciate the efforts of the Bureau of State Audits and its
consultant in preparing this report.
If you have any questions, please contact me or your staff may contact
Peter Garris, Deputy Director of California Energy Resources Scheduling, at
(916) 574-2733.
(Signed by: Stephen W. Verigin for)
Thomas M. Hannigan
Director
(916) 653-7007
115522 California State Auditor Report 2002-009 California State Auditor Report 2002-009 115533
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
115522 California State Auditor Report 2002-009 California State Auditor Report 2002-009 115533