Edgar Filing: PACIFIC GAS & ELECTRIC CO

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As filed with the Securities and Exchange Commission on March 2, 2004

Registration No. 333-109994

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 1

Form S-3

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Pacific Gas and Electric Company

(Exact Name of Registrant as Specified in Its Charter)


California (State or Other Jurisdiction of Incorporation or Organization)		77 Beale Street P.O. Box 770000 San Francisco, CA 94177 (415) 973-7000 (Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)		94-0742640 (I.R.S. Employer Identification Number)

Bruce R. Worthington

Senior Vice President and General Counsel

PG&E Corporation

One Market Spear Tower, Suite 2400

San Francisco, CA 94105

(415) 267-7000

(Name, Address, Including Zip Code, and Telephone Number,

Including Area Code, of Agent for Service)

Approximate date of commencement of proposed sale to the public: From time to time after the effective date of this Registration Statement.

If the only securities being registered on this form are being offered pursuant to dividend or interest reinvestment plans, please check the following box. o

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, other than securities offered only in connection with dividend or interest reinvestment plans, check the following box. þ

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. o

CALCULATION OF REGISTRATION FEE






Title of Each Class		Proposed Maximum	Proposed Maximum
of Securities to Be	Amount to Be	Offering Price Per	Aggregate Offering	Amount of
Registered	Registered	Debt Security	Price	Registration Fee


Senior Secured Bonds	$9,400,000,000(1)	100%(1)(2)(3)	$9,400,000,000(1)(2)(3)	$760,460



(1)	Includes an indeterminate principal amount of senior secured bonds as may from time to time be issued at indeterminate prices; provided that in no event will the aggregate initial price of all senior secured bonds sold under this registration statement exceed $9,400,000,000. If any such senior secured bonds are issued at an original issue discount, then the aggregate initial offering price as so discounted shall not exceed $9,400,000,000, notwithstanding that the stated aggregate principal amount of such senior secured bonds may exceed such amount.



(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act, as amended. The proposed maximum initial offering price per security will be determined from time to time by the registrant in connection with the issuance of the senior secured bonds.


(3)	Exclusive of accrued interest, if any.

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

PROSPECTUS

$9,400,000,000

Pacific Gas and Electric Company

Senior Secured Bonds

Under this prospectus, we may offer and sell from time to time senior secured bonds, or senior bonds, with an aggregate initial offering price of up to $9,400,000,000 in one or more offerings. This prospectus provides you with a general description of the senior bonds that may be offered.

Each time we sell senior bonds, we will provide a prospectus supplement that contains specific information about the offering and the terms of the offered senior bonds. The prospectus supplement also may add, delete, update or change information contained in this prospectus. You should carefully read this prospectus and any applicable prospectus supplement for the specific offering before you invest in any of the senior bonds. This prospectus may not be used to sell senior bonds unless accompanied by a prospectus supplement.

After the effective date of our plan of reorganization, the senior bonds will be secured by a first lien, subject to permitted liens, on substantially all our real property and certain other tangible personal property related to our facilities. The lien securing the senior bonds, however, may be released in certain circumstances, subject to certain conditions. Upon a release of the lien, the senior bonds will cease to be our secured obligations and will become our unsecured general obligations, ranking pari passu with our other senior unsecured indebtedness.

The senior bonds may be sold to or through underwriters, dealers or agents or directly to other purchasers. A prospectus supplement will set forth the names of any underwriters, dealers or agents involved in the sale of the senior bonds, the aggregate principal amount of senior bonds to be purchased by them and the compensation they will receive.

We were incorporated in California in 1905. Our principal executive offices are located at 77 Beale Street, San Francisco, California 94177, and our telephone number at that location is (415) 973-7000.

Please see “Risk Factors” beginning on page 1 for a discussion of factors you should

consider in connection with a purchase of the senior bonds offered by this prospectus.

None of the Securities and Exchange Commission, any state securities commission or any other regulatory body has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

March , 2004

TABLE OF CONTENTS


	Page

About This Prospectus		ii
Special Note Regarding Forward-Looking Statements		iii
Risk Factors		1
Use of Proceeds		8
Selected Consolidated Financial Data		9
Management’s Discussion and Analysis of Financial Condition and Results of Operations		11
Quantitative and Qualitative Disclosures About Market Risk		46
Description of Our Plan of Reorganization		50
Business		57
Management		94
Description of the Senior Secured Bonds		96
Plan of Distribution		116
Experts		117
Legal Matters		117
Where You Can Find More Information		117
Index to Consolidated Financial Statements and Unaudited Condensed Financial Statements		F-1

Unless otherwise indicated, when used in this prospectus, the terms “we,” “our,” “ours” and “us” refer to Pacific Gas and Electric Company and its subsidiaries, and the term “Corp” refers to our parent, PG&E Corporation.

UNITS OF MEASUREMENT


1 Kilowatt (kW)	=	One thousand watts
1 Kilowatt-Hour (kWh)	=	One kilowatt continuously for one hour
1 Megawatt (MW)	=	One thousand kilowatts
1 Megawatt-Hour (MWh)	=	One megawatt continuously for one hour
1 Gigawatt (GW)	=	One million kilowatts
1 Gigawatt-Hour (GWh)	=	One gigawatt continuously for one hour
1 Kilovolt (kV)	=	One thousand volts
1 MVA	=	One megavolt ampere
1 Mcf	=	One thousand cubic feet
1 MMcf	=	One million cubic feet
1 Bcf	=	One billion cubic feet
1 Decatherm (Dth)	=	Ten therms, also equivalent to one million British thermal units
1 MDth	=	One thousand decatherms

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement that we filed with the Securities and Exchange Commission, or the SEC, using a shelf registration process. Under this shelf registration process, we may from time to time sell senior bonds with an aggregate initial offering price of up to $9.4 billion in one or more offerings.

This prospectus provides you with only a general description of the senior bonds that we may offer. This prospectus does not contain all of the information set forth in the registration statement of which this prospectus is a part, as permitted by the rules and regulations of the SEC. For additional information regarding us and the offered senior bonds, please refer to the registration statement of which this prospectus is a part. Each time we sell senior bonds, we will provide a prospectus supplement that contains specific information about the offering and the terms of the offered senior bonds. The prospectus supplement also may add, delete, update or change information contained in this prospectus. You should rely only on the information in the applicable prospectus supplement if this prospectus and the applicable prospectus supplement are inconsistent. Before purchasing any senior bonds, you should carefully read both this prospectus and the applicable prospectus supplement, together with the additional information described under the section of this prospectus titled “Where You Can Find More Information.”

You should rely only on the information contained or incorporated by reference in this prospectus and in any applicable prospectus supplement. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. Neither we nor any underwriter, dealer or agent will make an offer to sell the senior bonds in any jurisdiction where the offer or sale is not permitted. You should assume that the information in this prospectus and any applicable prospectus supplement is accurate only as of the dates on their covers. Our business, financial condition, results of operations and prospects may have changed since those dates.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus, the documents incorporated by reference in this prospectus and any applicable prospectus supplement contain various forward-looking statements. These forward-looking statements can be identified by the use of words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “might,” “will,” “should,” “could,” “goal,” “potential” and similar expressions. We base these forward-looking statements on our current expectations and projections about future events, our assumptions regarding these events and our knowledge of facts at the time the statements are made. These forward-looking statements are subject to various risks and uncertainties that may be outside our control, and our actual results could differ materially from our projected results. These risks and uncertainties include, among other things:



	•	the timing and resolution of the pending applications for rehearing of the approval by the California Public Utilities Commission, or the CPUC, of the settlement agreement it entered into with us on December 19, 2003, or the settlement agreement, and any appeals that may be filed with respect to the disposition of the rehearing applications;



	•	the timing and resolution of the pending appeals of the confirmation by the U.S. Bankruptcy Court for the Northern District of California, or the bankruptcy court, of our plan of reorganization that incorporates the settlement agreement, or our plan of reorganization;



	•	whether the investment grade credit ratings and other conditions required to implement our plan of reorganization are obtained or satisfied;



	•	future equity and debt market conditions, future interest rates and other factors that may affect our ability to implement our plan of reorganization;



	•	the impact of other current and future ratemaking actions of the CPUC, including the outcome of our 2003 general rate case;



	•	prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, the U.S. Congress, the CPUC, the Federal Energy Regulatory Commission, or the FERC, and the Nuclear Regulatory Commission, or the NRC, with regard to allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities, among other factors;



	•	the extent to which the CPUC or the FERC delays or denies recovery of our costs, including electricity purchase costs, from customers due to a regulatory determination that the costs were not reasonable or prudent or for other reasons;



	•	the extent to which our residual net open position increases or decreases (our residual net open position is the amount of electricity we need to meet the electricity demands of our customers, plus applicable reserve margins, that is not satisfied from our own generation facilities, our existing electricity purchase contracts and the California Department of Water Resources, or the DWR, electricity purchase contracts allocated to our customers, or the DWR allocated contracts);



	•	weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, cause damage to our assets or disrupt our operations or those of third parties on which we rely;



	•	unanticipated changes in our operating expenses or capital expenditures;



	•	the level and volatility of wholesale electricity and natural gas prices and supplies, and our ability to manage and respond to the level and volatility successfully;



	•	whether we are required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations and policies;

iii



	•	increased competition as a result of the takeover by condemnation of our distribution assets, duplication of our distribution assets or service by local public utility districts, self-generation by our customers and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery;



	•	the extent to which our distribution customers switch between purchasing electricity from us and purchasing electricity from alternate energy service providers, thus becoming direct access customers, and the extent to which cities, counties and others in our service territory begin directly serving our customers or combine to form community choice aggregators;



	•	the operation of our Diablo Canyon power plant, which exposes us to potentially significant environmental and capital expenditure outlays, and, to the extent we are unable to increase our spent fuel storage capacity by 2007 or find an alternative depository, the risk that we may be required to close our Diablo Canyon power plant and purchase electricity from more expensive sources;



	•	acts of terrorism;



	•	unanticipated population growth or decline, changes in market demand, demographic patterns or general economic and financial market conditions, including unanticipated changes in interest or inflation rates;



	•	the outcome of pending litigation;



	•	whether we are determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses;



	•	actions of credit rating agencies after the effective date of our plan of reorganization; and



	•	significant changes in our relationship with our employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur.

For additional factors that could affect the validity of our forward-looking statements, you should read the section of this prospectus titled “Risk Factors.”

You should read this prospectus and any applicable prospectus supplements, the documents that we have filed as exhibits to the registration statement of which this prospectus is a part and the documents that we refer to under the section of this prospectus titled “Where You Can Find More Information” completely and with the understanding that our actual future results could be materially different from what we currently expect. We qualify all our forward-looking statements by these cautionary statements. These forward-looking statements speak only as of the date of this prospectus. Except as required by applicable laws or regulations, we do not undertake any obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

RISK FACTORS

You should carefully consider the risks and uncertainties described below and the other information contained in this prospectus or any applicable prospectus supplement or incorporated by reference in this prospectus before you decide whether to purchase the senior bonds. The risks and uncertainties described below are not the only ones we may face. The following risks, together with additional risks and uncertainties not currently known to us or that we may currently deem immaterial, could impair our business operations and ultimately affect our ability to make payments on the senior bonds.

Risks Related to Us


	If either or both of the CPUC’s approval of the settlement agreement and the bankruptcy court’s confirmation of our plan of reorganization are overturned or modified on rehearing or appeal, our financial condition and results of operations could be materially adversely affected.

The settlement agreement, which was approved by the CPUC in a decision issued on December 18, 2003, provides the basis for our plan of reorganization. On December 22, 2003, the bankruptcy court confirmed our plan of reorganization, which fully incorporates the settlement agreement as a material and integral part of the plan. On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the settlement agreement. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. In addition, the two CPUC commissioners who did not vote to approve the settlement agreement and a municipality have filed appeals of the bankruptcy court’s confirmation order in the U.S. District Court for the Northern District of California, or the district court. If either or both of the CPUC’s approval of the settlement agreement and the bankruptcy court’s confirmation of our plan of reorganization are overturned or modified on rehearing or appeal, our financial condition and results of operations could be materially adversely affected.

In addition, the terms of our plan of reorganization permit us and Corp to cause our plan of reorganization to become effective and permit us to issue a significant portion of the senior bonds while the CPUC’s approval of the settlement agreement and the bankruptcy court’s confirmation of our plan of reorganization remain subject to appeal. If, after our plan of reorganization has become effective and the proceeds of any offering of the senior bonds have been released to us and used to pay allowed claims in our proceeding under Chapter 11 of the U.S. Bankruptcy Code, or our Chapter 11 proceeding, the bankruptcy court’s confirmation order is subsequently overturned or modified, our ability to make payments on the senior bonds could be materially adversely affected.


	*Our financial viability depends upon our ability to recover our costs in a timely manner from our customers through regulated rates and otherwise execute our business strategy.*

We are a regulated entity subject to CPUC jurisdiction in almost all aspects of our business, including the rates, terms and conditions of our services, procurement of electricity and natural gas for our customers, issuance of securities, dispositions of utility assets and facilities and aspects of the siting and operation of our electricity and natural gas distribution systems. Executing our business strategy depends on periodic CPUC approvals of these and related matters. Our ongoing financial viability depends on our ability to recover from our customers in a timely manner our costs, including the costs of electricity and natural gas purchased by us for our customers, in our CPUC-approved rates and our ability to pass through to our customers in rates our FERC-authorized revenue requirements. During the California energy crisis, the high price we had to pay for electricity on the wholesale market, coupled with our inability to fully recover our costs in retail rates, caused our costs to significantly exceed our revenues and ultimately caused us to file a petition under Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11. Even though the settlement agreement and current regulatory mechanisms contemplate that the CPUC will give us the opportunity to recover our reasonable and prudent future costs in our rates, there can be no assurance that the CPUC will find that all of our costs are reasonable and prudent or will not otherwise take or fail to take actions to our detriment. In addition, there can be no assurance that the bankruptcy court or other courts will implement and enforce the terms of the settlement agreement and our plan of reorganization in a manner that would produce the economic results that we intend or anticipate. Further, there can be no assurance that FERC-authorized tariffs will be adequate to cover the related costs. If we are

unable to recover any material amount of our costs through our rates in a timely manner, our financial condition and results of operations would be materially adversely affected.


	We may be unable to purchase electricity in the wholesale market or to increase our generating capacity in a manner that the CPUC will find reasonable or in amounts sufficient to satisfy our residual net open position.

The electricity we generate and have under contract, combined with the electricity furnished under the DWR allocated contracts, may not be sufficient to satisfy our customers’ electricity demands in the future. Our residual net open position is expected to grow over time for a number of reasons, including:


	•	periodic expirations of our existing electricity purchase contracts;


	•	periodic expirations or other terminations of the DWR allocated contracts;



	•	increases in our customers’ electricity demands due to customer and economic growth or other factors; and



	•	retirement or closure of our electricity generation facilities.

In addition, unexpected outages at our Diablo Canyon power plant or any of our other significant generation facilities, or a failure to perform by any of the counterparties to our electricity purchase contracts or the DWR allocated contracts, would immediately increase our residual net open position.

In January 2004, the CPUC adopted an interim decision that would require the California investor-owned electric utilities to achieve, no later than January 1, 2008, an electricity reserve margin of 15-17% in excess of peak capacity electricity requirements and have a diverse portfolio of electricity sources. These requirements may increase our residual net open position. Specific procedures contained in the decision relating to development and execution of our procurement plans also may cause our cost of electricity to increase. The CPUC also continued its target of a 5% limitation on the reliance by the California investor-owned electric utilities on the spot market to meet their energy needs.

As existing electricity purchase contracts expire, sources of electricity otherwise become unavailable or demand increases, we will purchase electricity in the wholesale market. These purchases will be made under contracts priced at the time of execution or, if made in the spot market, at the then-current market price of wholesale electricity. There can be no assurance that sufficient replacement electricity will be available at prices and on terms that the CPUC will find reasonable, or at all. Our financial condition and results of operations would be materially adversely affected if we are unable to purchase electricity in the wholesale market at prices or on terms the CPUC finds reasonable or in quantities sufficient to satisfy our residual net open position.

Alternatively, the CPUC may require us, or we may elect, to satisfy all or a part of our residual net open position by developing or acquiring additional generation facilities. This could result in significant additional capital expenditures or other costs and may require us to issue additional debt, which we may not be able to issue on reasonable terms, or at all. In addition, if we are not able to recover a material part of the cost of developing or acquiring additional generation facilities in our rates in a timely manner, our financial condition and results of operations would be materially adversely affected.


	*Our financial condition and results of operations could be materially adversely affected if we are unable to successfully manage the risks inherent in operating our facilities.*

We own and operate extensive electricity and natural gas facilities that are interconnected to the U.S. western electricity grid and numerous interstate and continental natural gas pipelines. The operation of our facilities and the facilities of third parties on which we rely involves numerous risks, including:


	•	operating limitations that may be imposed by environmental or other regulatory requirements;


	•	imposition of operational performance standards by agencies with regulatory oversight of our facilities;


	•	environmental and personal injury liabilities;

	•	fuel interruptions;


	•	blackouts;

	•	labor disputes;

	•	weather, storms, earthquakes, fires, floods or other natural disasters; and


	•	explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output or cause damage to our assets or operations or those of third parties on which we rely.

The occurrence of any of these events could result in lower revenues or increased expenses, or both, that may not be fully recovered through insurance, rates or other means in a timely manner, or at all.


	Electricity and natural gas markets are highly volatile and insufficient regulatory responsiveness to that volatility could cause events similar to those that led to the filing of our Chapter 11 petition to occur.

In the recent past, the commodity markets for electricity and natural gas have been highly volatile and subject to substantial price fluctuations. A variety of factors may contribute to commodity market volatility, including:


	•	weather;

	•	supply and demand;

	•	the availability of competitively priced alternative energy sources;

	•	the level of production of natural gas;

	•	the price of other fuels that are used to produce electricity, including crude oil and coal;

	•	the transparency, efficiency, integrity and liquidity of regional energy markets affecting California;


	•	electricity transmission or natural gas transportation capacity constraints;


	•	federal, state and local energy and environmental regulation and legislation; and

	•	natural disasters, war, terrorism and other catastrophic events.

These factors are largely outside our control. If wholesale electricity or natural gas prices increase significantly, public pressure or other regulatory or governmental influences or other factors could constrain the willingness or ability of the CPUC to authorize timely recovery of our costs. Moreover, the volatility of commodity markets could cause us to apply more frequently to the CPUC for authority to timely recover our costs in rates. If we are unable to recover any material amount of our costs in our rates in a timely manner, our financial condition and results of operations would be materially adversely affected.


	*Our operations are subject to extensive environmental laws, and changes in, or liabilities under, these laws could adversely affect our financial condition and results of operations.*

Our operations are subject to extensive federal, state and local environmental laws. Complying with these environmental laws has in the past required significant expenditures for environmental compliance, monitoring and pollution control equipment, as well as for related fees and permits. Moreover, compliance in the future may require significant expenditures relating to electric and magnetic fields, or EMFs. We also are subject to significant liabilities related to the investigation and remediation of environmental contamination at our current and former facilities, as well as at third-party owned sites. Due to the potential for imposition of stricter standards and greater regulation in the future and the possibility that other potentially responsible parties may not be financially able to contribute to cleanup costs, conditions may change or additional contamination may be discovered, our environmental compliance and remediation costs could increase, and the timing of our capital expenditures in the future may accelerate. If we are unable to recover the costs of complying with environmental laws in our rates in a timely manner, our financial condition and results of operations could be materially adversely affected. In addition, in the event we must pay materially more than the amount that we currently have reserved on our balance sheet to satisfy our environmental remediation obligations and we are unable to recover

these costs from insurance or through rates in a timely manner, our financial condition and results of operations would be materially adversely affected.


	We face the risk of unrecoverable costs if our customers obtain distribution and transportation services from other providers as a result of municipalization or other forms of competition.

Our customers could bypass our distribution and transportation system by obtaining service from other sources. Forms of bypass of our electricity distribution system include the construction of duplicate distribution facilities to serve specific existing or new customers, the municipalization of our distribution facilities by local governments or districts, self-generation by our customers and other forms of competition. Bypass of our system may result in stranded investment capital, loss of customer growth or additional barriers to cost recovery. Our natural gas transportation facilities also are at risk of being bypassed by customers who build pipeline connections that bypass our natural gas transportation system. As customers and local public officials explore their energy options in light of the recent California energy crisis, these bypass risks may be increasing and may increase further if our rates exceed the cost of other available alternatives. In addition, technological changes could result in the development of economically attractive alternatives to purchasing electricity through our distribution facilities. We cannot currently predict the impact of these actions and developments on our business, although one possible outcome is a decline in the demand for the services that we provide, which would result in a corresponding decline in our revenues.

If the number of our customers declines due to bypass, technological changes or other forms of competition, and our rates are not adjusted in a timely manner to allow us to fully recover our investment and electricity procurement costs, our financial condition and results of operations would be materially adversely affected.


	*We face the risk of unrecoverable costs resulting from changes in the number of customers in our service territory for whom we purchase electricity.*

As part of California’s electricity industry restructuring, our customers were given the choice of either continuing to receive electricity procurement, transmission and distribution services, or bundled service, from us, or purchasing electricity from alternate energy service providers, and to thus become direct access customers. The CPUC suspended the right of end-user customers to become direct access customers on September 20, 2001, although customers that were then direct access customers have been allowed to remain on direct access. Separately, the CPUC has instituted a rulemaking implementing California’s Assembly Bill 117, or AB 117, which permits California cities and counties to purchase and sell electricity for their residents once they have registered as community choice aggregators. We would continue to provide distribution, metering and billing services to the community choice aggregators’ customers. Once registration has occurred, each community choice aggregator would purchase electricity for all of its residents who do not affirmatively elect to continue to receive electricity from us. However, we would remain those customers’ electricity provider of last resort.

If we lose a material number of customers as a result of cities and counties electing to become community choice aggregators or the CPUC allowing customers to migrate to direct access, our electricity purchase contracts could obligate us to purchase more electricity than our remaining customers require, the excess of which we would have to sell in the wholesale spot market, possibly at a loss. Further, if we must provide electricity to customers discontinuing direct access or electing to leave a community choice aggregator, we may be required to make unanticipated purchases of additional electricity at higher prices.

If we have excess electricity or we must make unplanned purchases of electricity as a result of changes in the number of community choice aggregators’ customers or direct access customers, and the CPUC fails to adjust our rates to reflect the impact of these actions, our financial condition and results of operations could be materially adversely affected.


	*The operation and decommissioning of our nuclear power plants expose us to potentially significant liabilities and capital expenditures.*

The operation and decommissioning of our nuclear power plants expose us to potentially significant liabilities and capital expenditures, including those arising from the storage, handling and disposal of radioactive

materials and uncertainties related to the regulatory, technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. We maintain decommissioning trusts and external insurance coverage to reduce our financial exposure to these risks. However, the costs or damages we may incur in connection with the operation and decommissioning of nuclear power plants could exceed the amount of our insurance coverage and other amounts set aside for these potential liabilities. In addition, as an operator of two operating nuclear reactor units, we may be required under federal law to pay up to $201.2 million of liabilities arising out of each nuclear incident occurring not only at our Diablo Canyon power plant but at any other nuclear power plant in the United States. If we cannot recover any material amount of these excess costs or damages in our rates in a timely manner, our financial condition and results of operations would be materially adversely affected.

In addition, the NRC has broad authority under federal law to impose licensing and safety-related requirements upon owners and operators of nuclear power plants. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of the nuclear plant, or both, depending upon the NRC’s assessment of the severity of the situation. Safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at our Diablo Canyon power plant and additional significant capital expenditures could be required in the future.


	If we fail to increase the spent fuel storage capacity at our Diablo Canyon power plant by the spring of 2007 and there are no other available spent fuel storage or disposal alternatives, we would be forced to close this plant and would therefore be required to purchase electricity from more expensive sources.

Under the terms of the NRC operating licenses for our Diablo Canyon power plant, there must be sufficient storage capacity for the radioactive spent fuel produced by this plant. Under current operating procedures, we believe that our Diablo Canyon power plant’s existing spent fuel pools have sufficient capacity to enable it to operate until the spring of 2007. Although we are taking actions to increase our Diablo Canyon power plant’s spent fuel storage capacity and exploring other alternatives, there can be no assurance that we can obtain the necessary regulatory approvals to expand spent fuel capacity or that other alternatives will be available or implemented in time to avoid a disruption in production or shutdown of one or both units at this plant. As the proposed permanent spent fuel depository at Yucca Mountain, Nevada will not be available by 2007, there will not be any available third party spent fuel storage facilities. If there is a disruption in production or shutdown of one or both units at this plant, we will need to purchase electricity from more expensive sources.


	*Acts of terrorism could materially adversely affect our financial condition and results of operations.*

Our facilities, including our operating and retired nuclear facilities and the facilities of third parties on which we rely, could be targets of terrorist activities. A terrorist attack on these facilities could result in a full or partial disruption of our ability to generate, transmit, transport or distribute electricity or natural gas or cause environmental repercussions. Any operational disruption or environmental repercussions could result in a significant decrease in our revenues or significant reconstruction or remediation costs, which could materially adversely affect our financial condition and results of operations.


	*Adverse judgments or settlements in the chromium litigation cases could materially adversely affect our financial condition and results of operations.*

We are a named defendant in 14 civil actions currently pending in California courts relating to alleged chromium contamination. The chromium litigation complaints allege personal injuries, wrongful death and loss of consortium and seek unspecified compensatory and punitive damages based on claims arising from alleged exposure to chromium contamination in the vicinity of three of our natural gas compressor stations. If we pay a material amount in excess of the amount that we currently have reserved on our balance sheet to satisfy chromium-related liabilities and costs, our financial condition and results of operations could be materially adversely affected.


	*Changes in, or liabilities under, our permits, authorizations or licenses could adversely affect our financial condition and results of operations.*

Our operations are subject to a number of governmental permits, authorizations and licenses. These permits, authorizations and licenses may be revoked or modified by the agency that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, discharge permits and other approvals and licenses are often granted for a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. For example, we currently have eight hydroelectric generation facilities undergoing FERC license renewal. In connection with a license renewal, the FERC may impose new license conditions that could, among other things, require increased expenditures or result in reduced electricity output and/or capacity at the licensed hydroelectric generation facility. If we are unable to obtain, renew or comply with these governmental permits, authorizations or licenses, or we are unable to recover any increased costs of complying with additional license requirements or any other associated costs in a timely manner, our financial condition and results of operations could be materially adversely affected.

Risks Related to the Senior Bonds

After giving effect to our plan of reorganization, we will have a significant amount of debt, and the agreements governing that indebtedness will allow us to incur additional debt in the future, which could adversely affect our ability to make payments on the senior bonds.

After giving effect to our plan of reorganization (including the issuance of a significant portion of the senior bonds in connection with our plan of reorganization, reinstatement of certain pollution control bond-related obligations and payments to holders of allowed claims), we currently expect to have up to approximately $9.4 billion in total debt outstanding immediately after the effective date of our plan of reorganization (excluding rate reduction bonds and draws on our contemplated revolving credit and accounts receivable facilities). In addition, the indenture governing the senior bonds and the terms of our contemplated credit facilities will allow us to incur additional debt. Our level of debt could have important consequences to holders of the senior bonds. For example, additional debt could require us to dedicate a greater portion of our cash flow to paying interest expense and debt amortization, which would reduce the funds available to us for our operations and capital expenditures, limit our ability to obtain additional financing for capital expenditures, working capital or for other purposes, and increase our vulnerability to adverse economic, regulatory and industry conditions.

Our ability to make scheduled payments of principal and interest on the senior bonds and to satisfy our other debt obligations will depend on the cash flow from our operations and other available sources of liquidity, such as equity offerings or additional debt financings. We can provide no assurance that these sources of liquidity will be available to us, if and when needed, or on terms acceptable to us. The amount of debt we expect to have outstanding after giving effect to our plan of reorganization and the establishment of the contemplated credit and accounts receivable facilities, as well as future indebtedness levels, could adversely affect our ability to make payments of principal and interest on the senior bonds.


	*There is no existing market for the senior bonds, and we cannot assure you that an active trading market will develop.*

There is no existing market for the senior bonds and we do not intend to apply for listing of the senior bonds on any securities exchange or any automated quotation system. There can be no assurance as to the liquidity of any market that may develop for the senior bonds, the ability of the holders of the senior bonds to sell their senior bonds or the price at which holders of the senior bonds will be able to sell their senior bonds. Future trading prices of the senior bonds will depend on many factors, including prevailing interest rates, our financial condition and results of operations, the then-current ratings assigned to the senior bonds and the market for similar securities.

If a particular offering of senior bonds is sold to or through underwriters, the underwriters may attempt to make a market in the senior bonds. However, the underwriters would not be obligated to do so and they could terminate any market-making activity at any time without notice. If a market for any of the senior bonds does

not develop, holders of those senior bonds may be unable to resell them for an extended period of time and those senior bonds may not be readily accepted as collateral for loans.


	*The terms of our debt instruments could restrict our flexibility and limit our ability to make payments on the senior bonds.*

The indenture for the senior bonds restricts the amount and type of secured indebtedness that we may incur. Our contemplated credit facilities also contain financial and operational covenants. In addition, the instruments governing future indebtedness that we may incur could also contain financial covenants and other restrictions on us. These covenants and restrictions could limit our flexibility and limit our ability to borrow additional funds to finance operations and to make principal and interest payments on the senior bonds. In addition, failure to comply with these covenants could result in an event of default under the terms of the agreements that, if not cured or waived, could result in the indebtedness becoming due and payable. The effect of these covenants, or our failure to comply with them, could materially adversely affect our business, financial condition, results of operations and our ability to satisfy our obligations under the senior bonds.


	*The senior bonds are expected to become unsecured obligations in the future.*

When the senior bonds are issued, they will be secured by a lien on substantially all of our real property and certain tangible personal property related to our facilities. The indenture provides that the lien may be released when the ratings assigned by Moody’s Investors Service, or Moody’s, and Standard & Poor’s, or S&P, on our long-term unsecured debt obligations immediately after the release of the lien would be at least equal to the initial ratings on the senior bonds issued to the public in connection with our plan of reorganization and when the aggregate amount of debt secured by a lien on any principal property that would be outstanding after the date the lien is released, or the release date, excluding debt secured by specified liens, would not exceed 5% of our tangible net assets, as defined in the indenture. After the release date, there will be no collateral securing the senior bonds and the senior bonds will become our unsecured general obligations ranking pari passu with all of our other senior unsecured debt. In addition, if our senior unsecured credit ratings fall after the release date, we will not be required to again secure the senior bonds. We also may maintain and incur certain types and amounts of secured debt after the release date. The absence of collateral securing the senior bonds could materially adversely affect the ability of holders of the senior bonds to collect payments should we default on our obligations or go back into bankruptcy after the effective date of our plan of reorganization.


	*Holders of senior bonds may be limited in their remedies with respect to the collateral.*

If an event of default occurs under the indenture for the senior bonds before the release date, the trustee under the indenture has the right to exercise remedies against the collateral securing the senior bonds. The trustee will take any action, if requested to do so by the holders of at least 33% (at least a majority prior to the release date) of the aggregate principal amount of outstanding senior bonds and if the trustee has been offered reasonable indemnity. Thus, you may not be able to control the trustee’s exercise of remedies unless you can obtain the consent of at least 33% (at least a majority prior to the release date) of the aggregate principal amount of outstanding senior bonds and provide the trustee with reasonable indemnity. In addition, provisions of California law limit the remedies of a lender secured by a mortgage. In light of the extensive number of real properties subject to the lien of the indenture, foreclosure may be very difficult and time consuming. In addition, the sale or other disposition of all or a portion of our real property in connection with a foreclosure could require approval or other action by applicable regulatory authorities, including the CPUC, the FERC and the NRC. If we go back into bankruptcy after the effective date of our plan of reorganization, there could be adverse effects on the senior bonds that could result in delays or reductions in payments to the holders of the senior bonds. In addition, bankruptcy could have an adverse effect on the liquidity and value of the senior bonds.


	*The sale of the collateral may provide insufficient proceeds to satisfy all the obligations secured by the collateral.*

The senior bonds will be secured by a lien on substantially all of our real property and certain tangible personal property related to our facilities. The value of the property in the event of liquidation will depend upon market and economic conditions, the availability of buyers and other factors. Some or all of the real and personal

property subject to the lien of the indenture may be illiquid, may have no readily ascertainable market value or may not be saleable on a timely basis or at all. If the proceeds of the sale of the property subject to the lien are not sufficient to repay all amounts due on the senior bonds, your right to obtain the shortfall from us or from our remaining assets may be limited or eliminated by California law. Since the indenture will permit us to secure other obligations with liens on any of our properties or assets that do not secure the senior bonds, our remaining assets available to satisfy our obligations to you may be further reduced. In addition, the indenture permits us to issue additional secured debt, including additional senior bonds. This could reduce amounts payable to you from the proceeds of the sale of collateral.

USE OF PROCEEDS

Each prospectus supplement will describe the uses of the proceeds from the issuance of the senior bonds offered by that prospectus supplement.

SELECTED CONSOLIDATED FINANCIAL DATA

The following table presents our selected consolidated financial data for the years ended December 31, 2003, 2002, 2001, 2000 and 1999. We derived the selected consolidated financial data for the years ended December 31, 2003, 2002 and 2001 from our audited consolidated financial statements included in this prospectus and the selected consolidated financial data for the years ended December 31, 2000 and 1999 from our consolidated financial statements not included in this prospectus. Our historical operating results are not necessarily indicative of future operations. The data below should be read in conjunction with, and is qualified in its entirety by reference to, our consolidated financial statements, the notes to those financial statements and the section of this prospectus titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



		Year Ended December 31,

		2003			2002			2001			2000			1999


		(dollars in millions)
Consolidated Statements of Operations Data:
Operating revenues:
	Electricity	$	7,582		$	8,178		$	7,326		$	6,854		$	7,232
	Natural gas		2,856			2,336			3,136			2,783			1,996

	Total operating revenues		10,438			10,514			10,462			9,637			9,228
Operating expenses:
	Depreciation, amortization and decommissioning		1,218			1,193			896			3,511			1,564
	Other operating expenses		6,881			5,408			7,088			11,327			5,671

	Total operating expenses		8,099			6,601			7,984			14,838			7,235

Operating income (loss)(1)			2,339			3,913			2,478			(5,201	)		1,993
Interest expense(2)			(953	)		(988	)		(974	)		(619	)		(593	)
Other income			66			72			107			183			36
Income tax (provision) benefit			(528	)		(1,178	)		(596	)		2,154			(648	)

Net income (loss) from continuing operations(1)			924		$	1,819		$	1,015		$	(3,483	)	$	788

Other Data (unaudited):
Ratio of earnings to fixed charges(3)			2.51x			3.91x			2.58x			—x	(4)		3.25x
EBITDA(5)		$	3,623		$	5,178		$	3,481		$	(1,507	)	$	3,593



	December 31,

	2003		2002		2001		2000			1999


	(in millions)
Consolidated Balance Sheet Data:
Cash and cash equivalents	$	2,979	$	3,343	$	4,341	$	1,344		$	101
Restricted cash		403		150		53		50			—
Working capital		3,555		3,399		4,291		(6,192	)		(1,603	)
Net property, plant and equipment		18,102		16,978		16,193		15,635			15,110
Total assets		29,066		27,593		28,105		24,622			23,862
Debt, classified as current		600		571		623		5,743			1,204
Long-term debt		2,431		2,739		3,019		3,342			4,877
Rate reduction bonds (excluding current portion)		870		1,160		1,450		1,740			2,031
Liabilities subject to compromise		9,502		9,408		11,384		—			—
Preferred securities with mandatory redemption provisions		137		137		437		437			437
Shareholders’ equity		5,089		4,194		2,398		1,410			5,771



(1)	Operating income (loss) and net income (loss) from continuing operations reflect the write-off of generation-related regulatory assets and undercollected electricity purchase costs in 2000.



(2)	Interest expense includes non-contractual interest expense of $131 million, $149 million and $164 million for the years ended December 31, 2003, 2002 and 2001, respectively.



(3)	For the purpose of computing ratios of earnings to fixed charges, “earnings” represent net income adjusted for income taxes and fixed charges. “Fixed charges” include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases and the amount of earnings required to cover the preferred security distribution requirements of our wholly owned trust.



(4)	The ratio of earnings to fixed charges indicates a deficiency of less than one-to-one coverage of $5.6 billion.



(5)	EBITDA is defined as income before provision for income taxes, interest expense and depreciation, amortization and decommissioning. We believe that EBITDA provides a comparative measure for operating performance and is a standard measure commonly reported and widely used by analysts, investors and other parties as an indication of our ability to service our debt. EBITDA is not intended to represent net cash provided by operating activities and should not be considered as an alternative to net income as an indicator of operating performance or to cash flows as a measure of liquidity. EBITDA is not a measurement of operating performance computed in accordance with accounting principles generally accepted in the United States of America, or GAAP, and it should not be considered a substitute for operating income or cash flows from operations prepared in conformity with GAAP. Our method of computation may or may not be comparable to other similarly titled measures used by other companies.

EBITDA is calculated from net income (loss) from continuing operations (which we believe to be the most directly comparable financial measures calculated in accordance with GAAP). The following is a reconciliation of EBITDA to both net income (loss) from continuing operations and net cash provided by operating activities:



		Year Ended December 31,

		2003			2002			2001			2000			1999


		(in millions)
Net income (loss) from continuing operations		$	924		$	1,819		$	1,015		$	(3,483	)	$	788
Adjustments to reconcile EBITDA to net income (loss) from continuing operations:
	Depreciation, amortization and decommissioning		1,218			1,193			896			3,511			1,564
	Interest expense		953			988			974			619			593
	Income tax provision (benefit)		528			1,178			596			(2,154	)		648

EBITDA		$	3,623		$	5,178		$	3,481		$	(1,507	)	$	3,593
Adjustments to reconcile EBITDA to net cash provided by operating activities:
	Cash paid for interest		(773	)		(1,105	)		(361	)		(587	)		(531	)
	Cash (paid) refunded for taxes		(648	)		(1,186	)		556			—			(1,001	)
	Deferral of electric procurement costs		—			—			—			(6,465	)		—
	Provision for loss on generation-related regulatory assets and undercollected purchased power costs		—			—			—			6,939			—
	Reversal of Independent System Operator accrual		—			(970	)		—			—			—
	Change in deferred charges and other non-current liabilities		581			102			(954	)		480			101
	Change in working capital (other than income taxes payable)		(653	)		363			2,379			2,263			464
	Payments authorized by bankruptcy court		(87	)		(1,442	)		(16	)		—			—
	Other, net		(73	)		194			(320	)		(568	)		(430	)

Net cash provided by operating activities		$	1,970		$	1,134		$	4,765		$	555		$	2,196

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

You should read the following discussion in conjunction with the sections of this prospectus titled “Special Note Regarding Forward-Looking Statements,” “Risk Factors,” “Selected Consolidated Financial Data” and the financial statements and related notes included elsewhere in this prospectus.

Overview

We are a public utility operating in northern and central California. We engage primarily in the businesses of electricity and natural gas distribution, electricity generation, electricity transmission, and natural gas transportation and storage. We are a wholly owned subsidiary of Corp. We were incorporated in California in 1905.

We served approximately 4.9 million electricity distribution customers and approximately 3.9 million natural gas distribution customers at December 31, 2003. We had approximately $29.1 billion in assets at December 31, 2003 and generated revenues of approximately $10.4 billion in 2003. Our revenues are generated mainly through the sale and delivery of electricity and natural gas. We are regulated primarily by the CPUC and the FERC.


	*Restructuring of the California Electricity Industry*

In 1996, California enacted Assembly Bill, or AB, 1890, which mandated the restructuring of the California electricity industry and established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity. As required by AB 1890, beginning January 1, 1997, electricity rates for all customers were frozen at the level in effect on June 10, 1996 and, beginning January 1, 1998, rates for residential customers were further reduced by 10%. The frozen rates were designed to allow us to recover our authorized utility costs and, to the extent the frozen rates generated revenues greater than these costs, to recover our costs stranded by the regulatory change, or transition costs.

AB 1890 also gave customers the choice of continuing to buy electricity from the California investor-owned electric utilities or, beginning in April 1998, becoming direct access customers. We bill direct access customers based on fully bundled rates, or rates that include electricity procurement, generation, distribution, transmission and other components. We then give direct access customers energy credits equal to the procurement component of the fully bundled rates, or direct access credits.


	*The California Energy Crisis and Our Chapter 11 Proceeding*

Beginning in May 2000, wholesale electricity prices began to increase so that the frozen rates were not sufficient to recover our operating and electricity procurement costs. We financed the higher costs of wholesale electricity by issuing debt in the fall of 2000 and drawing on our credit facilities. Ultimately, our inability to recover our electricity procurement costs from our customers resulted in billions of dollars in defaulted debt and unpaid bills. On April 6, 2001, we filed a voluntary petition for relief under the provisions of Chapter 11 in the bankruptcy court. We retained control of our assets and are authorized to operate our business as a debtor-in-possession during our Chapter 11 proceeding.

In January 2001, because of the deteriorating credit of the California investor-owned electric utilities, the DWR began purchasing electricity to meet each utility’s net open position, which is the portion of the demand of a utility’s customers, plus applicable reserve margins, not satisfied from that utility’s own generation facilities and existing electricity contracts. The DWR is currently legally and financially responsible for its electricity contracts. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power charge. These customers also must pay another revenue requirement, which is known as a bond charge, for the DWR’s costs associated with its $11.3 billion bond offering completed in November 2002. On January 1, 2003, each California investor-owned electric utility resumed purchasing electricity to meet its residual net open position.

In January 2001, the CPUC authorized us to collect the first of three electricity surcharges intended to help us reduce the impact of the high wholesale electricity prices. The rate surcharges totaled $0.045 per kWh, and were fully implemented by June 2001.

In mid-2001, wholesale electricity prices moderated. As a result of these surcharges and moderating electricity prices, our net income and cash balances increased. This has allowed us to pay our post-petition operating expenses and other post-petition liabilities with internally generated funds. In addition, we have paid interest on certain pre-petition liabilities and the principal of maturing mortgage bonds with bankruptcy court approval.


	*Our Plan of Reorganization and Settlement Agreement*

In September 2001, we and Corp proposed a plan of reorganization that would have disaggregated our businesses. In April 2002, the CPUC, later joined by the Official Committee of Unsecured Creditors, proposed an alternate plan of reorganization that would not have disaggregated our businesses. On December 19, 2003, we, the CPUC and Corp entered into the settlement agreement that contemplated a new plan of reorganization to supersede the competing plans. Under the settlement agreement, we remain vertically integrated. On December 22, 2003, the bankruptcy court confirmed our plan of reorganization, which fully incorporates the settlement agreement. Our plan of reorganization provides that we will pay all allowed creditor claims in full (except for the claims of holders of certain pollution control bond-related obligations that will be reinstated) from the proceeds of the public offering of a significant portion of the senior bonds, cash on hand and draws on credit and accounts receivable facilities. At December 31, 2003, allowed claims in our Chapter 11 proceeding amounted to approximately $12.3 billion.

The settlement agreement permits us to emerge from Chapter 11 as an investment grade entity by generally ensuring that we will have the opportunity to collect in rates reasonable costs of providing our utility service. The settlement agreement provides that our authorized return on equity will be no less than 11.22% per year and, except for 2004 and 2005, our authorized equity to capitalization ratio, or authorized equity ratio, will be no less than 52% until Moody’s has issued us an issuer rating of not less than A3 or S&P has issued us a long-term issuer credit rating of not less than A-. The settlement agreement establishes a $2.21 billion after-tax regulatory asset and allows for the recognition of an approximately $800 million after-tax regulatory asset related to generation assets. The settlement agreement and related decisions by the CPUC provide that our revenue requirement will be collected regardless of sales levels and that our rates will be timely adjusted to accommodate changes in costs that we incur.

On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the settlement agreement. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. In addition, the two CPUC commissioners who did not vote to approve the settlement agreement and a municipality have appealed the bankruptcy court’s confirmation order in the U.S. District Court for the Northern District of California, or the district court. On January 5, 2004, the bankruptcy court denied a request to stay the implementation of our plan of reorganization until the appeals are resolved. The district court will set a schedule for briefing and argument of the appeals at a later date. No additional parties may request rehearings or make appeals of the CPUC’s approval of the settlement agreement or the bankruptcy court’s confirmation order.

Implementation of our plan of reorganization is subject to various conditions, including the consummation of the public offering of the senior bonds, the receipt of investment grade credit ratings and final CPUC approval of the settlement agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed by us and Corp to constitute final approval. Thus, the terms of our plan of reorganization permit us and Corp to cause our plan of reorganization to become effective (and permit us to issue a significant portion of the senior bonds) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of our plan of reorganization discussed above are resolved further, we do not believe

that the applicable accounting probability standard needed to record the regulatory assets contemplated by the settlement agreement has been met. We believe that we and the senior bonds to be issued in connection with our plan of reorganization will receive investment grade credit ratings. We expect that the sale of the senior bonds will be the last condition of our plan of reorganization to be satisfied. Our plan of reorganization provides that the effective date will occur 11 business days after all the conditions have been satisfied or, with respect to certain conditions, waived by us and Corp. There can be no assurance that the settlement agreement will not be modified on rehearing or appeal or that our plan of reorganization will become effective.


	*2004 Rate Reduction*

In early January 2004, the CPUC issued a decision finding that the rate freeze mandated by AB 1890 ended on January 18, 2001. In mid-January 2004, we entered into a rate design settlement agreement, or rate design settlement, with representatives of major customer groups that addresses revenue allocation and rate design issues associated with the decrease in our revenue requirements resulting from the settlement agreement, DWR revenue requirements and other CPUC actions. On February 26, 2004, the CPUC issued a decision adopting the rate design settlement. This decision, combined with the January 2004 CPUC decision regarding the rate freeze, provides that we will no longer collect the frozen rates and surcharges. Instead, we will collect the regulatory assets arising from the settlement agreement, as amortized into rates, the revenue requirements established by the 2003 general rate case and revenue requirements established in other proceedings. We have reached an agreement, or general rate case settlement, with several consumer groups to resolve our 2003 general rate case and set our electricity and natural gas revenue requirements and our electricity generation revenue requirement through 2006. The general rate case settlement is pending CPUC approval. As a result of the approval of the rate design settlement, our electricity customers will receive an electricity rate reduction of approximately 8.0% on average, starting in March 2004, or shortly thereafter, retroactive to January 1, 2004. We expect that as a result of this rate reduction, our electricity operating revenues will decrease by approximately $799 million compared to revenues generated at rates in effect prior to the implementation of the rate design settlement. If the general rate case settlement is not approved, the net average reduction in electricity rates and associated reduction in electricity operating revenue will be even greater.


	*Significant Factors Affecting Results*

Our results of operations will be affected by whether and when the settlement agreement and our plan of reorganization are implemented. Other significant factors that affect our results of operations include:



	•	CPUC decisions affecting the rates that we can charge for our services and determining the costs that are allowable for recovery within our rate structure;



	•	the amount and cost of electricity purchased;



	•	other operating expenses; and



	•	the performance of distribution, generation, transmission and transportation operating assets.

The CPUC has broad influence over our operations. Our revenue requirements are authorized primarily by the CPUC and the CPUC approves the rates that we charge our customers. The CPUC is responsible for setting service levels and certain operating practices which have a significant impact on the amount of costs we incur. The CPUC is also responsible for reviewing our capital and operating costs and in certain cases prescribes specific accounting treatment.

Electricity procurement costs historically have impacted our results of operations and financial condition. California legislation has been enacted which allows us to recover substantially all our prospective wholesale electricity procurement costs and requires the CPUC to adjust rates on a timely basis to ensure that we recover our costs. Accordingly, for 2004 and beyond, electricity procurement costs are not expected to have the same impact on our results of operations that they had during the California energy crisis. However, the level of our electricity procurement costs will continue to have an impact on our cash flows.

Operating expenses are a key factor in determining whether we earn the rate of return authorized by the CPUC. Many of our costs, including electricity procurement costs, discussed above, are subject to ratemaking mechanisms that are intended to provide us the opportunity to fully recover these costs. However, there is no ratemaking mechanism for recovery of our operating and maintenance expenses. As a result, changes in our operating expenses impact our results of operations.

Our distribution, generation, transmission and transportation operating assets generally consist of long-lived assets with significant construction and maintenance costs. Our annual capital expenditures are expected to average approximately $1.7 billion annually over the next five years. A significant outage at any of our facilities may have a material impact on our operations. Costs associated with replacement electricity and natural gas or use of alternative facilities during these outages could have an adverse impact on our results of operations and liquidity.

Reporting

Our consolidated financial statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and repayment of liabilities in the ordinary course of business.

The consolidated financial statements include our accounts and those of our wholly owned and controlled subsidiaries. This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements and notes to the consolidated financial statements.

Our Chapter 11 Proceeding and CPUC Settlement Agreement

On December 19, 2003, we, Corp and the CPUC entered into the settlement agreement and, on December 22, 2003, the bankruptcy court confirmed our plan of reorganization which fully incorporates the settlement agreement.

Terms and Financial Impact of the Settlement Agreement

The principal terms of the settlement agreement that will affect our results of operations and liquidity include:

Regulatory Assets. The settlement agreement establishes a $2.21 billion after-tax regulatory asset (which is equivalent to an approximately $3.7 billion pre-tax regulatory asset) as a new, separate and additional part of our rate base to be amortized on a “mortgage-style” basis over nine years retroactive to January 1, 2004. Under this amortization methodology, annual after-tax collections of the $2.21 billion regulatory asset in electricity rates are estimated to range from approximately $140 million in 2004 to approximately $380 million in 2012, although these amounts will be reduced as discussed below. The unamortized balance of this after-tax regulatory asset will earn a rate of return on its equity component of no less than 11.22% annually for its nine-year term. The rate of return on this regulatory asset would be eliminated if we complete the refinancing discussed below. Instead, we would collect from customers amounts sufficient to service the securitized debt. The net after-tax amount of any refunds, claim offsets or other credits we receive from energy suppliers related to specified electricity procurement costs incurred during the California energy crisis, including from a settlement, or the El Paso settlement, involving El Paso Natural Gas Company, or El Paso, related to electricity refunds, but not natural gas refunds, will reduce the outstanding balance of this regulatory asset. Under the rate design settlement approved by the CPUC on February 26, 2004, the reduction to the regulatory asset related to the El Paso settlement and certain other generator refunds, claim offsets or other credits is forecast to be $179 million, after-tax. The estimated amount will be subject to adjustment based on actual amounts received by us. Additional refunds, claim offsets and other credits would further reduce this regulatory asset. Reductions of the regulatory asset reduce the amount amortized into rates.

In addition, as part of the settlement agreement, the CPUC will deem our adopted 2003 electricity generation rate base of approximately $1.6 billion to be just and reasonable and not subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and changes in authorized

depreciation. This reaffirmation would allow recognition of an approximately $800 million after-tax regulatory asset (which is equivalent to an approximately $1.3 billion pre-tax regulatory asset).

We expect to recognize the pre-tax amounts of the two regulatory assets once we determine, in accordance with GAAP, that these regulatory assets are probable of recovery, as discussed above. This recognition would increase our total assets by approximately $5.0 billion. It also will result in the recording of approximately $2.0 billion of deferred tax liabilities that would be recognized as income tax expense. In addition, the recognition of these regulatory assets and related deferred taxes will result in a one-time non-cash gain of approximately $3.0 billion of net income for the year of recognition, with a similar increase in our shareholders’ equity. The portion of these amounts attributable to the $2.21 billion after-tax regulatory asset will be reduced for refunds, claim offsets and other credits received.

Ratemaking. Under the terms of the settlement agreement, the CPUC has agreed to act timely upon our applications to collect in rates prudently incurred costs of any new, reasonable investment in utility plant and assets and has agreed to timely adjust our rates to ensure that we collect in rates fixed amounts to service existing rate reduction bonds, regulatory asset amortization and return and base revenue requirements. In addition, the CPUC has agreed to set our capital structure and authorized return on equity in our annual cost of capital proceedings in its usual manner. From January 1, 2004 until Moody’s has issued an issuer rating for us of not less than A3 or S&P has issued a long-term issuer credit rating for us of not less than A-, our authorized return on equity will be no less than 11.22% per year and our authorized equity ratio will be no less than 52%. However, for 2004 and 2005, our authorized equity ratio will equal the greater of the proportion of equity approved in our 2004 and 2005 cost of capital proceedings, or 48.6%.

The CPUC agreed in the settlement agreement to maintain our retail electricity rates at their pre-existing level through the end of 2003. In 2004, we will no longer collect the revenue generated by the frozen rates and surcharges that we collected in 2003, 2002 and 2001. Instead, we will collect revenues designed to recover the regulatory assets, as amortized into rates, and the revenue requirements established by the 2003 general rate case and other regulatory proceedings. Although revenue requirements would increase over previously authorized amounts if the pending general rate case settlement is approved by the CPUC, the elimination of the surcharges and frozen rates will result in a net average reduction of electricity rates effective March 2004, or shortly thereafter, retroactive to January 1, 2004. In addition, we will recognize expenses related to the amortization of the regulatory assets in 2004 and beyond, expenses not present in 2003. The amortization of the regulatory assets would have no direct impact on cash flow because amortization is a non-cash expense. The decrease in rates will, however, reduce cash flow. Other than the one-time impact of recording net income associated with recognition of the regulatory assets discussed above, overall implementation of the settlement agreement and related rulemaking will decrease our net income in 2004 as compared to 2003. In addition, if the general rate case settlement is not approved, the amount of the rate reduction and revenue reduction will increase.

Securitization. We and Corp have agreed to seek to refinance up to a total of $3.0 billion of the unamortized pre-tax balance of the $2.21 billion after-tax regulatory asset, as expeditiously as practicable after the effective date of our plan of reorganization using a financing supported by a dedicated rate component, provided certain conditions are met. These conditions include the enactment of authorizing California legislation satisfactory to us, the CPUC, and The Utility Reform Network, or TURN, and that the securitization not adversely affect our credit ratings. We expect to use the securitization proceeds to rebalance our capital structure in order to achieve the capital structure provided in the settlement agreement.

After the securitization, the rate of return on this regulatory asset would be eliminated. Instead, we would collect from customers amounts sufficient to service the securitized debt. Electricity rates would be further reduced to reflect the lower cost of capital of the securitization financing, causing a corresponding decrease in our net income.

Cash Requirements of Our Plan of Reorganization

Our plan of reorganization provides for payment in full in cash of all allowed creditor claims (except for the claims of holders of approximately $814 million of pollution control bond-related obligations that will be reinstated), plus applicable interest on claims in certain classes, and all cumulative dividends in arrears and

mandatory sinking fund payments associated with our outstanding preferred stock. The following is a summary of all claims we have recorded at December 31, 2003 (including all claims related to obligations that will be reinstated at the effective date of our plan of reorganization):


		Amount Owed

		(in millions)
Revolving line of credit		$	938
Bank borrowing — letters of credit for accelerated pollution control loan agreements			454
Floating rate notes			1,240
Commercial paper			873
Senior notes			680
Pollution control loan agreements			814
Medium-term notes			287
Deferrable interest subordinated debentures			300
Other long-term debt			17

	Financing debt subject to compromise		5,603
Trade creditors subject to compromise			3,899
Mortgage bonds			2,741
Interest and dividends			20

	Total	$	12,263

On March 1, 2004, we made an approximately $310 million principal payment on maturing mortgage bonds with bankruptcy court approval. We expect to pay all remaining allowed claims (other than claims represented by reinstated obligations) on or as soon as practicable after the effective date of our plan of reorganization and to establish escrow accounts to pay disputed claims as they are resolved. We expect that we will require approximately $11.0 billion in cash to pay the allowed claims and make the necessary escrow deposits. In addition, $814 million outstanding under the pollution control loan agreements will be reinstated. We expect to offset allowed power procurement claims with amounts owed to us by the California Power Exchange, or PX. This netting reduces the cash requirement of our plan of reorganization by approximately $500 million.

We expect to use approximately $2.8 billion of cash on hand after retirement of the mortgage bonds to pay allowed claims and make necessary escrow deposits. In accordance with our plan of reorganization, the balance of the cash requirements will be met with a public offering of a significant portion of the senior bonds and draws on various credit and accounts receivables facilities.

Results of Operations

The table below details certain items from the accompanying consolidated statements of operations for 2003, 2002 and 2001:



			Year Ended December 31,

			2003			2002			2001


			(in millions)
Operating revenues
	Electricity		$	7,582		$	8,178		$	7,326
	Natural gas			2,856			2,336			3,136

		Total operating revenues		10,438			10,514			10,462
Operating expenses
	Cost of electric energy			2,319			1,482			2,774
	Cost of natural gas			1,467			954			1,832
	Operating and maintenance			2,935			2,817			2,385
	Depreciation, amortization and decommissioning			1,218			1,193			896
	Reorganization professional fees and expenses			160			155			97

		Total operating expenses		8,099			6,601			7,984

Operating income				2,339			3,913			2,478
Reorganization interest income				46			71			91
Interest income				7			3			32
Interest expense:
	Contractual interest expense			(822	)		(839	)		(810	)
	Noncontractual interest expense			(131	)		(149	)		(164	)
Other income (expense), net				13			(2	)		(16	)

Income before income taxes				1,452			2,997			1,611
Income tax provision				528			1,178			596

Income before cumulative effect of a change in accounting principle				924			1,819			1,015
Cumulative effect of a change in accounting principle (net of income tax benefit of $1 million for 2003)				(1	)		—			—

Net income				923			1,819			1,015
Preferred dividend requirement				22			25			25

Income available for (allocated to) common stock			$	901		$	1,794		$	990


	*Overview*

The following presents our operating results for 2003, 2002 and 2001. As described below, net income for 2003 reflects a decline in operating revenues compared to 2002 as a result of increases in the DWR’s revenue requirements and an increased cost of electricity because we resumed procuring electricity to cover our residual net open position in 2003. Net income for 2002 reflects an increase in operating revenues compared to 2001 due to increased electricity surcharge collections and a decrease in amounts passed through to the DWR. Although we are not able to predict all of the factors that may affect future results, results of operations in 2004 will be materially different from historical results if the settlement agreement is implemented, if the CPUC approves our general rate case settlement and as the rate design settlement is implemented.


	Electricity Operating Revenues

From mid-January 2001 through December 2002, the DWR was responsible for procuring electricity required to cover our net open position. We resumed purchasing electricity on the open market in January 2003 to satisfy our residual net open position, but still rely on electricity provided under DWR contracts for a material portion of our customers’ demand. Revenues collected on behalf of the DWR and the DWR’s related costs are not included in our consolidated statements of operations, reflecting our role as a billing and collection agent for

the DWR’s sales to our customers. Under the frozen rate structure, increases in the revenues passed through to the DWR decreased our revenues.

In January 2001, the CPUC authorized us to collect an electricity surcharge, the first of three surcharges intended to help the California investor-owned electric utilities pay for the high cost of wholesale electricity. The surcharges, totaling $0.045 per kWh, were fully implemented by June 2001 and were collected through December 31, 2003, while frozen rates remained in place.

The following table shows a breakdown of our electricity operating revenue by customer class:


		2003			2002			2001


		(in millions)
Residential		$	3,671		$	3,646		$	3,396
Commercial			4,440			4,588			4,105
Industrial			1,410			1,449			1,554
Agricultural			522			520			525
Miscellaneous			59			316			380
Direct access credits			(277	)		(285	)		(461	)
DWR pass-through revenue			(2,243	)		(2,056	)		(2,173	)

	Total electricity operating revenues	$	7,582		$	8,178		$	7,326

In 2003, our electricity operating revenues decreased approximately $596 million, or 7%, compared to 2002 mainly due to the following factors:


	•	Pass-through revenue to the DWR increased by approximately $187 million, or 9%, in 2003 from 2002. This increase was mainly due to an aggregate increase of $1.0 billion in DWR power and bond charges, partially offset by an approximately $444 million reduction in the 2003 DWR revenue requirement and an approximately $369 million adjustment recorded in the third quarter of 2002 to reflect required changes to the methodology used to calculate DWR pass-through revenues.

The reduction in the DWR’s 2003 revenue requirement was mainly due to a September 2003 CPUC decision that reduced the DWR’s approved revenue requirement for 2003. The decision also required us to pass the benefit of the revenue requirement reduction on to our customers through a one-time bill credit in 2003. As a result, the approximately $444 million reduction in the 2003 DWR revenue requirement was offset by a corresponding reduction in electricity operating revenues for each customer class in 2003.



	•	We recorded a regulatory liability or reserve for the potential refund of approximately $125 million of surcharge revenues collected in 2003 as provided by the terms of the rate design settlement entered into in January 2004 and approved by the CPUC on February 26, 2004.



	•	Due to an April 2002 CPUC decision that increased baseline quantity allowances that was applied for all of 2003 but only a portion of 2002, electricity operating revenues decreased by an additional $44 million in 2003. An increase to a customer’s baseline quantity allowance increases the amount of the customer’s monthly usage that is covered under the lowest possible rate and is exempt from certain surcharges.



	•	The decrease in electricity operating revenues was partially offset by the collection of a cost responsibility surcharge, a non-bypassable charge to direct access customers for their share of certain costs incurred by us. The CPUC implemented this surcharge on January 1, 2003 and we collected approximately $187 million in cost responsibility surcharge revenues from direct access customers in 2003.

In 2002, our electricity operating revenues increased approximately $852 million, or 12%, compared to 2001 mainly due to the following factors:


	•	The amount of CPUC authorized surcharges increased approximately $751 million, or 34%, in 2002 from 2001. This increase reflects the collection of $0.045 per kWh in surcharges for all of 2002 compared to



		the collection of $0.01 per kWh in surcharges for substantially all of 2001 and the remaining $0.035 per kWh in surcharges for only seven months during 2001.



	•	Direct access credits decreased approximately $176 million, or 38%, in 2002 from 2001 mainly due to a decrease in the average direct access credit per kWh, partially offset by an increase in the total electricity provided to direct access customers by alternate energy service providers. The average direct access credit per kWh was lower in 2002 than in 2001 because in the beginning of 2001 we used the PX price for wholesale electricity to calculate direct access credits. After the PX closed in January 2001, direct access credits have been calculated based on the electricity procurement component of the fully bundled rate, which has been significantly lower than the PX price. The average direct access credit decreased from $0.116 per kWh in 2001 to $0.038 per kWh in 2002. In 2002, alternate energy service providers supplied approximately 7,433 GWh of electricity to direct access customers, compared to approximately 3,982 GWh in 2001.



	•	Revenue passed through to the DWR decreased by approximately $117 million, or 5%, in 2002 from 2001. This decrease was mainly due to a decrease in our net open position, which resulted in less DWR electricity being delivered to our customers. The decrease in our net open position was caused by increases in the number of direct access customers and in the amount of electricity we were able to purchase from qualifying facilities due to renegotiated payment terms. In addition, we accrued approximately $369 million in additional pass through revenues to the DWR in 2002 due to changes proposed by the DWR to the methodology used to calculate DWR remittances. Absent this accrual, the decrease in the revenue passed through to the DWR would have been greater.

We will no longer collect the frozen rates and surcharges that we collected in 2003, 2002 and 2001 after the implementation of the rate design settlement. Instead, revenues in 2004 will be based on an aggregation of individual rate components, including base revenue requirements, electricity procurement costs and the DWR revenue requirement, among others. Changes in the DWR revenue requirements will change rates charged to certain of our customers. As a result, changes in amounts passed through to the DWR will no longer affect our results of operations. The rate design settlement will reduce electricity rates by approximately 8.0%, on average, and result in a reduction of electricity operating revenues of approximately $799 million.


	Cost of Electricity

Our cost of electricity includes electricity purchase costs and the cost of fuel used by our owned generation facilities but it excludes costs to operate our generation facilities. The following table shows a breakdown of our cost of electricity and the total amount and average cost of purchased power, excluding, in each case, both the cost and volume of electricity provided by the DWR to our customers:


		2003			2002			2001


		(costs, except averages,
		in millions)
Cost of purchased power		$	2,449		$	1,980		$	3,224
Proceeds from surplus sales allocated to us			(247	)		—			—
Fuel used in owned generation			117			97			102
Adjustments to purchased power accruals			—			(595	)		(552	)

	Total net cost of electricity	$	2,319		$	1,482		$	2,774

Average cost of purchased power per kWh		$	0.076		$	0.081		$	0.143

Total purchased power (GWh)			32,249			24,552			22,592

In 2003, our cost of electricity increased approximately $837 million, or 56%, compared to 2002 mainly due to the following factors:



	•	Our total volume of electricity purchased in 2003 increased 31% because we resumed buying and selling electricity on the open market beginning in the first quarter of 2003 to meet our residual net open position in accordance with our CPUC-approved electricity procurement plan.



	•	The increase in total costs was partially offset by proceeds from surplus electricity sales. We are required to dispatch all of the electricity resources within our portfolio, including electricity provided under DWR contracts, in the most cost-effective way. This requirement, in certain cases, requires us to schedule more electricity than is necessary to meet our retail load and to sell this additional electricity on the open market. We typically schedule this excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract. Proceeds from the sale of surplus electricity are allocated between us and the DWR based on the percentage of volume supplied by each entity to our total load. Our net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.



	•	In March 2002, we recorded a net reduction of approximately $595 million to the cost of electricity as a result of FERC and CPUC decisions that allowed us to reverse previously accrued Independent System Operator, or ISO, charges and to adjust for the amount previously accrued as payable to the DWR for its 2001 revenue requirement. There was no comparable reduction in 2003.

In 2002, our cost of electricity decreased approximately $1.3 billion, or 47%, compared to 2001 because our average cost of purchased power decreased compared to 2001 mainly due to the significantly lower prices for electricity after the energy market stabilized in the second half of 2001. In addition, the DWR purchased all of the electricity needed to meet our net open position for all of 2002, whereas in 2001 we purchased the electricity ourselves through the PX market through the first half of January 2001.

In 2002, FERC and CPUC decisions allowed us to reverse previously accrued ISO charges and adjust previously accrued DWR pass-through revenues, reducing the cost of electricity by a net of approximately $595 million. In 2001, we recorded approximately $552 million for the market value of terminated bilateral contracts, reducing the cost of electricity by approximately $552 million for that year. The net effect of these adjustments contributed to an additional decrease of approximately $43 million in the cost of electricity in 2002.

Our cost of electricity in 2004 will be dependent upon electricity prices and our residual net open position.


	Natural Gas Operating Revenues

The following table shows a breakdown of our natural gas operating revenues:


		2003		2002		2001


		(revenues, except averages,
		in millions)
Bundled natural gas revenues		$	2,572	$	2,020	$	2,761
Transportation service-only revenues			284		316		375

	Total natural gas operating revenues	$	2,856	$	2,336	$	3,136

Average bundled revenue per Mcf of natural gas sold		$	9.22	$	7.16	$	10.19

Total bundled natural gas sales (in Bcf)			279		282		271

In 2003, our total natural gas operating revenues increased approximately $520 million, or 22%, compared to 2002 mainly due to the following factors:


	•	Bundled natural gas revenues increased by approximately $552 million, or 27%, in 2003 from 2002 mainly due to a higher average cost of natural gas, which we are permitted by the CPUC to pass on to our customers through higher rates. The average bundled revenue per Mcf of natural gas sold in 2003



		increased $2.06, or 29%, compared to 2002. Natural gas prices increased in 2003 mainly due to a shortage in natural gas supply and lower storage reserves.



	•	Transportation service-only revenues decreased by approximately $32 million, or 10%, in 2003 from 2002 mainly due to a decrease in demand for natural gas transportation services by certain noncore customers, mainly natural gas-fired electric generators in California. An increase in electricity available from hydroelectric facilities and the greater efficiency of generation facilities that commenced operations in 2003 resulted in reduced demand for natural gas transportation services.

In 2002, our total natural gas operating revenues decreased approximately $800 million, or 26%, compared to 2001 mainly due to the following factors:



	•	Bundled natural gas revenues decreased by approximately $741 million, or 27%, in 2002 from 2001 mainly due to a lower average cost of natural gas. The average bundled revenue per Mcf of natural gas sold in 2002 decreased $3.03, or 30%, compared to 2001. Natural gas prices decreased in 2002 mainly due to an overall increase in natural gas supply and higher storage reserves.



	•	Transportation service-only revenue decreased by approximately $59 million, or 16%, in 2002 from 2001 mainly due to a decrease in demand for gas transportation services by natural gas-fired electric generators in California.

Our natural gas revenues in 2004 are expected to increase due to natural gas distribution rate increases in the general rate case settlement and will be further impacted by changes in the cost of natural gas.


	Cost of Natural Gas

Our cost of natural gas includes the purchase cost of natural gas and transportation costs on interstate pipelines, but excludes the costs associated with our intrastate pipeline, which are included in operating and maintenance expense. The following table shows a breakdown of our cost of natural gas:


		2003		2002		2001


		(costs, except averages,
		in millions)
Cost of natural gas sold		$	1,336	$	853	$	1,593
Cost of natural gas transportation			131		101		239

	Total cost of natural gas	$	1,467	$	954	$	1,832

Average cost per Mcf of natural gas sold		$	4.79	$	3.02	$	5.88

Total natural gas sold (in Bcf)			279		282		271

In 2003, our total cost of natural gas sold increased approximately $513 million, or 54%, compared to 2002 mainly due to the following factors:



	•	Our cost of natural gas sold increased approximately $483 million, or 57%, in 2003 from 2002 mainly due to an increase in the average cost of natural gas sold in 2003 of $1.77 per Mcf, or 59%.



	•	Our cost of natural gas transportation increased by approximately $30 million, or 30%, in 2003 from 2002 mainly due to pipeline transportation charges paid to El Paso. We, along with other California utilities, were ordered by the CPUC in July 2002 to enter into new long-term contracts to purchase firm transportation services on the El Paso pipeline, under which we pay a fixed amount to secure capacity on the El Paso pipeline.

In 2002, our total cost of natural gas sold decreased approximately $878 million, or 48%, compared to 2001 mainly due to the following factors:


	•	Our cost of natural gas sold decreased by approximately $740 million, or 46%, in 2002 from 2001 mainly due to a decrease of $2.86 per Mcf, or 49%, in the average cost of natural gas sold.


	•	Our cost of natural gas transportation decreased by approximately $138 million, or 58%, in 2002 from 2001 mainly due to approximately $111 million in costs recognized in 2001 related to the involuntary termination of natural gas transportation hedges caused by a decline in our credit rating. There were no similar events in 2002.

Our cost of natural gas sold in 2004 will be affected by the prevailing costs of natural gas, which are determined by North American regions that supply us.


	Operating and Maintenance

Operating and maintenance expenses consist mainly of our costs to operate our electricity and natural gas facilities, maintenance expenses, customer accounts and service expenses, administrative and general expenses, and the net deferral of revenues and expenses based on the difference between certain revenues and expenses recognized under GAAP and those revenues and expenses recognized for regulatory purposes.

In 2003, our operating and maintenance expenses increased approximately $118 million, or 4%, compared to 2002 mainly due to a reversal of a liability of approximately $65 million for surcharge revenues in excess of ongoing procurement costs and half-cent surcharge revenue collections at the end of 2002. The remainder of the increase was mainly due to wage increases in 2003 and increases in employee benefit plan-related expenses due to a 15% decrease in returns on plan investments and a decrease in the discount rates used to calculate the present value of our benefit obligations from 6.75% to 6.25%.

These increases were partially offset by a net increase in deferred electricity transmission-related costs compared to 2002. Electricity transmission-related costs are included in the cost of electricity and consist mainly of charges imposed by the ISO for grid management services. To the extent we do not receive revenues sufficient to recover electricity transmission-related costs, the costs are deferred through a reduction of operating and maintenance expenses until recovered in rates.

In 2002, our operating and maintenance expenses increased approximately $432 million, or 18%, compared to 2001 mainly due to the following factors:



	•	Employee benefit plan-related expenses increased approximately $115 million in 2002 from 2001 mainly due to a 7% decrease in returns on plan investments and lower interest rates, which caused a decrease in the discount rate used to calculate the present value of our benefit obligations.



	•	Environmental related expenses increased approximately $54 million in 2002 from 2001 mainly due to an increase in third party liabilities.



	•	Our new customer billing system, which was implemented at the end of 2002, increased customer accounts and service expenses by approximately $23 million, or 9%, in 2002 from 2001. The increased cost in 2002 resulted from pre-implementation testing, validation and training costs.



	•	The net deferred electricity transmission-related costs increased approximately $142 million in 2002 from 2001.



	•	We began deferring overcollected electricity revenue associated with the rate reduction bonds in 2002. Total deferred revenue was approximately $85 million in 2002.


	Depreciation, Amortization and Decommissioning

In 2003, our depreciation, amortization and decommissioning expenses increased approximately $25 million, or 2%, compared to 2002 mainly due to an overall increase in our plant assets.

In 2002, our depreciation, amortization and decommissioning expenses increased approximately $297 million, or 33%, compared to 2001 mainly due to the amortization of approximately $290 million of the rate reduction bond regulatory asset that began in January 2002.


	Reorganization Fees and Expenses

In accordance with the American Institute of Certified Public Accountants’ Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” or SOP 90-7, we report reorganization fees and expenses separately on our consolidated statements of operations. These costs mainly include professional fees for services in connection with our Chapter 11 proceedings and totaled approximately $160 million in 2003, $155 million in 2002 and $97 million in 2001. Upon implementation of our plan of reorganization and repayment in cash of substantially all allowed creditor claims and applicable interest and dividends, as discussed above, we will no longer incur reorganization fees and expenses.


	Interest Income

In accordance with SOP 90-7, we report reorganization interest income separately on our Consolidated Statements of Operations. Reorganization interest income mainly includes interest earned on cash accumulated during our Chapter 11 proceedings. Interest income, including reorganization interest income, decreased approximately $21 million, or 28%, in 2003 from 2002 and approximately $49 million, or 40%, in 2002 from 2001. Decreases for both periods were mainly due to lower average interest rates earned on our short-term investments.


	Interest Expense

In 2003, our interest expense decreased approximately $35 million, or 4%, compared to 2002 mainly due to the reduction in the amount of rate reduction bonds outstanding, reflecting the declining principal balance of the rate reduction bonds and a lower amount of unpaid debts accruing interest. This decrease was partially offset by the recording of approximately $38 million interest payable to the DWR in 2003 based upon a CPUC decision issued in January 2004. The interest payable to the DWR compensates the DWR for prior underpayments resulting from ambiguities in the formula that determined the DWR remittance rate that were resolved in September 2003. We have filed an application for rehearing of this decision with the CPUC.

In 2002, our interest expense increased approximately $14 million, or 1%, compared to 2001 due to our Chapter 11 proceeding, which resulted in higher negotiated interest rates and an increased level of unpaid debts accruing interest.

As discussed above, our ongoing interest expense will be dependent upon the size of the refinancing and associated rates established at the effective date of our plan of reorganization.

Liquidity and Financial Resources


	*Overview*

At December 31, 2003, our cash and cash equivalents balance was approximately $3.4 billion, of which approximately $403 million was restricted. The principal source of our cash is payments from our customers. Since wholesale electricity prices moderated and electricity surcharges were fully implemented in mid-2001, the cash generated by our operations has exceeded our ongoing cash requirements. We primarily invest our cash in money market funds and in short-term obligations of the U.S. Government and its agencies.

During our Chapter 11 proceeding, we have not had access to the capital markets and have met all our ongoing cash requirements, including our capital expenditures requirements, with cash generated by our operations. In addition, we have paid interest on certain pre-petition liabilities and repaid the principal of maturing mortgage bonds with bankruptcy court approval. We expect to pay allowed creditor claims from the proceeds of a public offering of a significant portion of the senior bonds, cash on hand and draws on credit and accounts receivable facilities established in connection with the implementation of our plan of reorganization. We also will establish an escrow account for disputed claims and deposit cash into these accounts to pay the claims as they are resolved.

Of our cash and cash equivalents at December 31, 2003, approximately $403 million is restricted as to its use. The restrictions arise from deposits under certain third party agreements, amounts held in escrow as collateral required by the ISO and deposits securing workers’ compensation obligations.

After the effective date of our plan of reorganization, we expect to fund our operating expenses and capital expenditures program from internally generated funds. We will maintain revolving credit, letter of credit, accounts receivable and other short-term borrowing facilities in order to provide sufficient liquidity to fund seasonal changes in working capital, balancing account undercollections, and credit support for collateralized procurement activities. We also expect to utilize a portion of our internally generated funds to make scheduled debt service payments and to achieve and maintain the target capital structure provided in the settlement agreement by the second half of 2005. Once we reach this target capital structure, we will commence distributions to Corp in the form of dividends and stock repurchases. Thereafter, a small portion of our capital expenditures program is expected to be funded with the issuance of new debt securities.

Operating Activities

Our cash flows from operating activities consist of monthly sales to our customers and operating expenses, other than expenses such as depreciation that do not require the use of cash. Cash flows from operating activities are also impacted by collections of accounts receivable and payments of liabilities previously recorded.

Our cash flows from operating activities for 2003, 2002 and 2001 were as follows:


			2003			2002			2001


			(in millions)
Net income			$	923		$	1,819		$	1,015
Non-cash (income) expenses:
	Depreciation, amortization and decommissioning			1,218			1,193			896
	Net reversal of ISO accrual			—			(970	)		—
Change in accounts receivable				(590	)		212			105
Change in accrued taxes				48			(345	)		1,415
Other uses of cash:
	Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise			(87	)		(1,442	)		(16	)
Other changes in operating assets and liabilities				458			667			1,350

		Net cash provided by operating activities	$	1,970		$	1,134		$	4,765

Although net income decreased by approximately $896 million in 2003 compared to 2002, in 2003, net cash provided by operating activities increased by approximately $836 million compared to 2002 mainly due to the following factors:



	•	Payments on amounts classified as liabilities subject to compromise decreased by approximately $1.3 billion in 2003, compared to 2002 due to significant pre-petition and post-petition payments made in 2002 under bankruptcy court-approved settlements.



	•	Net cash provided by operating activities was partially offset by an increase in accounts receivable. This increase was mainly due to the settlement in 2003 of an amount payable to the DWR that was recorded as an offset to our customer accounts receivable balance in 2002. Amounts payable to the DWR are offset against amounts receivable from our customers for energy supplied by the DWR reflecting our role as a billing and collection agent for the DWR’s sales to our customers.



	•	Net income in 2002 included a non-cash reduction of approximately $970 million to cost of electricity related to the reversal of ISO charges.

In 2002, the net cash provided by operating activities decreased by approximately $3.6 billion compared to 2001, mainly due to the following factors:



	•	Our filing of our Chapter 11 petition in April 2001 automatically stayed all payments on then-existing liabilities. After the filing, we resumed paying our ongoing expenses in the ordinary course of business. As a result, the growth in accounts payable was approximately $1.1 billion lower in 2002 than in 2001.



	•	We received an approximately $1.1 billion income tax refund in 2001 and no comparable refund was received in 2002.



	•	In 2002, we repaid approximately $901 million in pre-petition liabilities owed to qualifying facilities under bankruptcy court-approved agreements.



	•	In 2002, under a bankruptcy court order, we paid approximately $1.0 billion in pre-petition and post-petition interest to holders of certain undisputed claims, trade creditors and certain other general unsecured creditors. These interest payments included approximately $433 million of accrued interest on financial debt previously classified as liabilities subject to compromise.

We will maintain revolving credit, letter of credit, accounts receivable and other short-term borrowing facilities in order to provide sufficient liquidity to fund seasonal changes in working capital, balancing account undercollections and credit support for collateralized procurement activities.

Investing Activities

Our investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to our customers. Cash flows from operating activities have been sufficient to fund our capital expenditure requirements during 2003, 2002 and 2001. Year to year variances depend upon the amount and type of construction activities, which can be influenced by storm and other damage.

Our cash flows from investing activities for 2003, 2002 and 2001 were as follows:


		2003			2002			2001


		(in millions)
Capital expenditures		$	(1,698	)	$	(1,546	)	$	(1,343	)
Net proceeds from sale of assets			49			11			—
Other investing activities, net			(114	)		26			5

	Net cash used by investing activities	$	(1,763	)	$	(1,509	)	$	(1,338	)

In 2003, net cash used by investing activities increased by approximately $254 million compared to 2002. This increase was mainly due to an increase in capital expenditures related to electricity transmission network upgrades and new electricity capacity and transmission development projects in 2003 and other investing activities during 2003. Cash flows from other investing activities related mainly to nuclear decommissioning funding and the change in nuclear fuel inventory during the period.

In 2002, net cash used by investing activities increased by approximately $171 million compared to 2001 mainly due to an increase in capital expenditures related to electricity transmission substation and line improvements intended to improve system reliability.

Financing Activities

During our Chapter 11 proceeding, our financing activities have been limited to repayment of secured debt obligations as authorized by the bankruptcy court. During this period, we have not had access to the capital markets. As discussed below, we expect to issue significant amounts of debt in connection with the implementation of our plan of reorganization and establish revolving credit and accounts receivable facilities to provide additional liquidity at and after the effective date of our plan of reorganization.

Our cash flows from financing activities for 2003, 2002 and 2001 were as follows:


		2003			2002			2001


		(in millions)
Net repayments under credit facilities and short-term borrowings		$	—		$	—		$	(28	)
Net long-term debt, matured, redeemed or repurchased			(281	)		(333	)		(111	)
Rate reduction bonds matured			(290	)		(290	)		(290	)
Other financing activities, net			—			—			(1	)

	Net cash used by financing activities	$	(571	)	$	(623	)	$	(430	)

In 2003, net cash used by financing activities decreased by approximately $52 million compared to 2002. With bankruptcy court approval, we repaid approximately $281 million in principal on our mortgage bonds that matured in August 2003. PG&E Funding, LLC, our wholly owned subsidiary, also repaid approximately $290 million in principal on its rate reduction bonds. The rate reduction bonds are not included in our Chapter 11 proceeding. PG&E Funding, LLC pays the principal and interest on the rate reduction bonds from a specific rate element in our customers’ bills. We remit the collection of these billings to PG&E Funding, LLC on a daily basis.

In 2002, net cash used by financing activities increased by approximately $193 million compared to 2001. With bankruptcy court approval, we repaid approximately $333 million in principal on our mortgage bonds that matured in March 2002. PG&E Funding, LLC also repaid approximately $290 million in principal on its rate reduction bonds during each of 2001 and 2002.

Financing activities used approximately $430 million of net cash in 2001 mainly for repayments of long-term debt and rate reduction bonds. The repayment of long-term debt included payments of approximately $18 million on medium-term notes and approximately $93 million for mortgage bonds before our Chapter 11 filing.

Future Liquidity

After the effective date of our plan of reorganization, we expect to fund our operating expenses and capital expenditures substantially from internally generated funds, although we may issue debt for these purposes in the future. In addition, on or about the effective date of our plan of reorganization, we expect to establish new credit and accounts receivable facilities. We currently anticipate establishing a three-year revolving credit facility of approximately $850 million to $1.1 billion and an accounts receivable facility of approximately $600 million to $750 million. These facilities are intended to be used for the purposes of funding our operating expenses and seasonal fluctuations in working capital, providing letters of credit and paying a small portion of the allowed claims under our plan of reorganization. We also expect to establish a $650 million letter of credit facility that will be used to provide credit support for $614 million of reinstated pollution control bond-related obligations. We may also obtain bridge financings that will allow us to reissue or remarket at a later date up to approximately $800 million in pollution control bonds that we will not be able to reinstate at the effective date of our plan of reorganization.

We expect that the cash we will retain after the effective date of our plan of reorganization, together with cash from operating activities and available under the credit facilities we expect to establish, as described above, will provide for seasonal fluctuations in cash requirements and will be sufficient to fund our operations and our capital expenditures for the foreseeable future.

Dividend Policy

We have not declared or paid any common or preferred dividends in 2003, 2002 or 2001. While in Chapter 11, we are prohibited from paying any common or preferred dividends without bankruptcy court approval. Among other restrictions, we must maintain a capital structure authorized by the CPUC. We expect to achieve the target capital structure provided in the settlement agreement by the second half of 2005.

Capital Expenditures and Commitments

The following table provides information about our contractual obligations and commitments at December 31, 2003. This table includes obligations based on their existing terms. We expect to repay some of these obligations on, or as soon as practicable after, the effective date of our plan of reorganization. This table does not include payments on the senior bonds and credit facilities we expect to establish, in connection with our plan of reorganization.



			Payments due by period

					Less than
			Total		1 year		1 - 3 years		3 - 5 years		More than 5 years


			(in millions)
Off Balance Sheet Commitments:
Power purchase agreements(1):
	Qualifying facilities		$	19,960	$	1,590	$	3,090	$	2,880	$	12,400
	Irrigation district and water agencies			624		69		118		113		324
	Other power purchase agreements			435		96		126		85		128
Natural gas supply and transportation				1,000		852		141		7		—
Nuclear fuel				194		90		25		27		52
Other commitments(2)				238		126		78		29		5
Employee benefits:
	Pension(3)			386		129		257		—		—
	Postretirement benefits other than pension(3)			194		65		129		—		—

Total off balance sheet commitments				23,031		3,017		3,964		3,141		12,909
Long-term debt:
	Liabilities not subject to compromise:
		Fixed rate principal obligations		2,741		310		289		—		2,142
	Liabilities subject to compromise:
		Fixed rate principal obligations		1,184		225		697		1		261
		7.90% Deferrable Interest Subordinated Debentures		300		—		—		—		300
		Variable rate principal obligations		614		349		265		—		—
Rate reduction bonds				1,160		290		580		290		—
Preferred dividends and redemption requirements(4)				198		41		31		79		47



(1)	This table does not include DWR allocated contracts because the DWR is currently legally and financially responsible for these contracts.



(2)	Includes commitments for operating lease agreements mostly for office space in the aggregate amount of approximately $91 million, capital infusion agreements for limited partnership interests in the aggregate amount of approximately $16 million, contracts to retrofit generation equipment at our facilities in the aggregate amount of approximately $62 million, load-control and self-generation CPUC initiatives in the aggregate amount of approximately $35 million, contracts for local and long-distance telecommunications and other software in the aggregate amount of $16 million and capital expenditures for which we have contractual obligations or firm commitments



(3)	Contribution estimates conform to forecasted amounts in the pending 2003 general rate case. Actual contributions are dependent upon the outcome of the 2003 general rate case. Contribution estimates after 2006 are subject to future general rate case test years.


(4)	Preferred dividend and redemption requirement estimates beyond 5 years do not include non-redeemable preferred stock dividend payments as these continue in perpetuity.


	*Contractual Commitments*

Our contractual commitments include power purchase agreements (including agreements with qualifying facilities, irrigation districts and water agencies and renewable energy providers), natural gas supply and transportation agreements, nuclear fuel agreements, operating leases and other commitments.


	Power Purchase Agreements

Qualifying Facilities. Our power purchase agreements with qualifying facilities require us to pay for energy and capacity. Energy payments are based on a qualifying facility’s actual electricity output and CPUC-approved energy prices, while capacity payments are based on a qualifying facility’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the qualifying facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement. Our capacity payments to qualifying facilities total approximately $500 million annually. Energy payments under power purchase agreements with qualifying facilities are typically based upon a CPUC-approved short-run avoided cost that is currently indexed to natural gas prices. Avoided costs are the incremental costs that an electric utility would incur to generate or purchase electricity but for the purchase from the qualifying facilities. As a result of the California energy crisis and our Chapter 11 filing, in July 2001, 197 qualifying facilities amended their contracts to fix their energy payments at $0.054 per kWh through July 2006. The remaining qualifying facility contracts calculate payment based on short-run avoided cost. Beginning in August 2006, the energy payments under all qualifying facility contracts will revert back to the short-run avoided cost rates.

At December 31, 2003, we had qualifying facility power purchase agreements with approximately 300 qualifying facilities for approximately 4,400 MW in operation. Agreements for approximately 4,000 MW expire between 2004 and 2028. Qualifying facility power purchase agreements for approximately 400 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. On January 22, 2004, the CPUC adopted a decision that requires California investor-owned electric utilities to allow owners of qualifying facilities with power purchase agreements expiring before the end of 2005 to extend these contracts for five years. Qualifying facility power purchase agreements accounted for approximately 20% of our 2003 electricity sources, approximately 25% of our 2002 electricity sources and approximately 21% of our 2001 electricity sources. No single qualifying facility power purchase agreement accounted for more than 5% of our electricity sources during any of these periods.

In a proceeding pending at the CPUC, we have requested refunds in excess of $500 million for overpayments from June 2000 through March 2001 made to qualifying facilities. Under the settlement agreement, the net after-tax amount of any qualifying facility refunds that we actually realize in cash, claim offsets or other credits would reduce the $2.21 billion after-tax regulatory asset. While we are unable to estimate the outcome of this proceeding, we believe the proceeding will not have a material adverse effect on our financial condition or results of operations.

Irrigation Districts and Water Agencies. We have contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, we must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements whether or not any hydroelectric power is supplied and variable payments for operating and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. Our irrigation district and water agency contracts accounted for approximately 5% of our 2003 electricity sources, approximately 4% of our 2002 electricity sources and approximately 3% of our 2001 electricity sources.


	Other Power Purchase Agreements

Electricity Purchases to Satisfy the Residual Net Open Position. On January 1, 2003, we resumed buying electricity to meet our residual net open position. During 2003, more than 14,000 GWh of energy were bought and sold in the wholesale market to manage the 2003 residual net open position. Most of our contracts entered

into in 2003 had terms of less than one year. During 2004, we plan to enter into contracts of longer duration to satisfy our near-term residual net open position.

Renewable Energy Requirement. California law requires that, beginning in 2003, each California investor-owned electric utility increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. We met our 2003 commitment and the CPUC has approved several contracts intended to meet our 2004 renewable energy requirement.


	Natural Gas Supply and Transportation Agreements

We purchase natural gas directly from producers and marketers in both Canada and the United States to serve our core customers. The contract lengths and natural gas sources of our portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. At December 31, 2003, we had a $10 million collateralized standby letter of credit and a pledge of our core natural gas customer accounts receivable for the purpose of securing the purchase of natural gas. We replaced the pledge of the natural gas customer accounts receivable and natural gas inventory with $400 million of letters of credit in March 2004.

We also have long-term natural gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm pipeline capacity as well as volumetric transportation charges. The total demand charges that we will pay each year may change periodically as a result of changes in regulated tariff rates. The total demand, net of sales of excess supplies, and volumetric transportation charges we incurred under these agreements were approximately $131 million in 2003, $101 million in 2002 and $239 million in 2001.


	Nuclear Fuel Agreements

We have purchase agreements for nuclear fuel. These agreements have terms ranging from two to five years and are intended to ensure long-term fuel supply. These agreements are with a number of large, well-established international producers of nuclear fuel in order to diversify our commitments and provide security of supply. Pricing terms are also diversified, ranging from fixed prices to base prices that are adjusted using published information. Deliveries provided under nine of the eleven contracts in place at the end of 2003 will end by 2005. In most cases, our nuclear fuel agreements are requirements-based. Payments for nuclear fuel amounted to approximately $57 million in 2003, $70 million in 2002 and $50 million in 2001.


	Western Area Power Administration Commitments

In 1967, we and the Western Area Power Administration, or WAPA, entered into several long-term power contracts governing the interconnection of our respective electricity transmission systems, the use of our electricity transmission and distribution systems by WAPA, and the integration of our respective customer demands and electricity resources. These contracts give us access to WAPA’s excess hydroelectric power and obligate us to provide WAPA with electricity when its resources are not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004. Termination is subject to FERC approval, which we expect to receive.

The contractual commitments table above does not include our WAPA commitment because the costs to fulfill our obligations to WAPA cannot be accurately estimated at this time. Both the purchase price and the amount of electricity WAPA will need from us in 2004 are uncertain. However, we expect that the cost of meeting our contractual obligations to WAPA will be greater than the amount that we receive from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, our estimated net costs, based upon our portfolio, including DWR power and bond charges and after subtracting revenues received from WAPA, for electricity delivered under the contracts were approximately $233 million in 2003, $127 million in 2002 and $350 million in 2001.


	Transmission Control Agreement

We are a party to a Transmission Control Agreement, or TCA, with the ISO and other participating transmission owners. As a transmission owner, we are required to give two years notice and receive regulatory approval if we wish to withdraw from the TCA. Under this agreement, the transmission owners, which also include Southern California Edison, or SCE, San Diego Gas & Electric Company and several municipal utilities, assign operational control of their electricity transmission systems to the ISO. In addition, as a party to the TCA, we are responsible for a share of the costs of reliability must-run, or RMR, agreements between the ISO and owners of the power plants subject to RMR agreements, or RMR plants. We are also an owner of some of these RMR plants for which we receive revenue from the ISO. Under the RMR agreements, RMR plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO’s demand.

At December 31, 2003, the ISO had RMR agreements for which we could be obligated to pay the ISO an estimated $446 million in net costs during the period January 1, 2004 to December 31, 2005. These costs are recoverable under applicable ratemaking mechanisms.

It is possible that we may receive a refund of RMR costs that we previously paid to the ISO. In June 2000, a FERC administrative law judge issued an initial decision approving rates that, if affirmed by the FERC, would require the subsidiaries of Mirant Corporation, or Mirant, that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to us, excess payments of approximately $340 million, including interest, for availability of Mirant’s RMR plants under these agreements. On July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 and on December 15, 2003, we filed claims in Mirant’s Chapter 11 proceeding including a claim for an RMR refund. We are unable to predict at this time when the FERC will issue a final decision on this issue, what the FERC’s decision will be, and the amount of any refunds, which may be impacted by Mirant’s Chapter 11 filing. It is uncertain how the resolution of this matter would be reflected in rates.


	Other Commitments

We have other commitments relating to operating leases, capital infusion agreements, equipment replacements, software licenses, the self-generation incentive program exchange agreements and telecommunication contracts.

At December 31, 2003, the future minimum payments related to other commitments were as follows:


		(in millions)

2004		$	126
2005			48
2006			30
2007			15
2008			14
Thereafter			5

	Total	$	238


	Financing Commitments

Our current commitments under financing arrangements include obligations to repay mortgage bonds, senior notes, medium-term notes, pollution control bond-related agreements, deferrable interest subordinated debentures, lines of credit, reimbursement agreements associated with letters of credit, floating rate notes and commercial paper, substantially all of which are pre-petition obligations. On the effective date of our plan of reorganization, we expect to reinstate certain pollution control bond-related obligations in the amount of approximately $814 million. The balance of the pre-petition obligations will be paid in full in cash, plus applicable interest, on or as soon as practicable after the effective date of our plan of reorganization. After the effective date, our obligations also will include, in addition to the reinstated pollution control bond-related

obligations, the amount of senior bonds that we sell and the credit and accounts receivable facilities that we establish in connection with the implementation of our plan of reorganization.

In addition, PG&E Funding, LLC must make scheduled payments on its rate reduction bonds. The balance owed on these bonds at December 31, 2003 was approximately $1.16 billion. Annual principal payments on the rate reduction bonds total approximately $290 million. The rate reduction bonds are expected to be fully retired by the end of 2007.

Capital Expenditures

Our investment in plant and equipment totaled approximately $1.7 billion in 2003, $1.5 billion in 2002 and $1.3 billion in 2001.

The following table reflects our estimated capital expenditures for the next five years. Capital expenditures for which contracts or firm commitments exist have, in addition to being included in the table below, been included in the table above, which details our contractual obligations and commitments at December 31, 2003.


	(in millions)

2004	$	1,695
2005		1,806
2006		1,569
2007		1,659
2008		1,716

Our significant capital expenditure projects include:



	•	new customer connections and expansion of the existing electricity and natural gas distribution systems anticipated to average approximately $400 million annually over the next five years;



	•	replacements and upgrades to portions of our electricity distribution system anticipated to average approximately $300 million annually over the next five years;



	•	replacement of natural gas distribution pipelines expected to total approximately $375 million over the next five years;



	•	substation upgrades and expansion of line capacity of the electricity transmission system expected to average approximately $260 million annually over the next five years;



	•	replacements and upgrades to our natural gas transportation facilities expected to total approximately $600 million over the next five years;



	•	replacement of turbines and steam generators and other equipment, including additional security measures at our Diablo Canyon power plant, replacements and upgrades to our hydroelectric generation facilities and costs associated with relicensing our hydroelectric generation facilities expected to average approximately $180 million annually over the next five years; and



	•	investment in common plant, including computers, vehicles, facilities and communications equipment, expected to average approximately $150 million annually over the next five years.

We anticipate that our capital expenditures in the next five years will be somewhat higher than capital expenditures in recent years. These additional expenditures are necessary to replace aging and obsolete equipment and accommodate anticipated electricity and natural gas load growth. We retain the ability to delay or defer substantial amounts of these planned expenditures in light of changing economic conditions and changing technology. It is also possible that these projects may be replaced by other projects. Consistent with past practice, we expect that any capital expenditures will be included in our rate base and recoverable in rates.

The discussion above does not include any capital expenditures for new generation facilities. The residual net open position is expected to increase over time. To meet this need, we will need to enter into contracts with third-party generators for additional supplies of electricity, develop or otherwise acquire additional generation

facilities or satisfy our residual net open position through a combination of contracts and additional generation facilities. The discussion above also does not include any capital expenditures necessary to implement advanced metering improvements.

Contingencies


	*Surcharge Revenues*

In January 2001, the CPUC authorized increases in electricity rates of $0.01 per kWh, in March 2001 of another $0.03 per kWh and in May 2001 of an additional $0.005 per kWh. The use of these surcharge revenues was restricted to “ongoing procurement costs” and “future power purchases.” In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the surcharges to be used to restore our financial health by permitting us to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. From January 2001 to December 31, 2003, we recognized total surcharge revenues of approximately $8.1 billion, pre-tax. The rate design settlement included a refund of approximately $125 million of surcharge revenues. We recorded a regulatory liability for the potential refund of approximately $125 million of surcharge revenues collected during 2003, which is reflected on our balance sheet at December 31, 2003. If the CPUC requires us to refund any amounts in excess of approximately $125 million, our earnings could be materially adversely affected.


	*Advanced Metering Improvements*

The CPUC is assessing the viability of implementing an advanced metering infrastructure for residential and small commercial customers. This infrastructure would enable the California investor-owned electric utilities to measure usage of electricity on a time-of-use basis and to charge demand responsive rates. The goal of demand responsive rates is to encourage customers to reduce energy consumption during peak demand periods and thereby reduce peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. We are implementing demand responsive tariffs for large industrial customers who already have advanced metering systems in place, and a statewide pilot program is in progress to test whether and to what extent residential and small commercial customers will respond to demand responsive rates. If the CPUC determines that it would be cost-effective to install advanced metering on a large-scale and orders us to proceed with large scale development of advanced metering for residential and small commercial customers, we expect that we would incur substantial costs to convert our meters, build the meter reading network, and build the data storage and processing facilities to bill our customers. We would expect to recover through rates the capital investments and any ongoing operating costs associated with implementing the advanced metering improvements. The total deployment of an advanced metering infrastructure to all of our electricity and natural gas customers using equipment and technology currently available may cost more than $1.0 billion (in 2003 dollars), based on a five-year installation schedule starting in 2005.


	*El Paso Settlement*

In June 2003, we, along with a number of other parties, entered into the El Paso settlement, which resolves all potential and alleged causes of action against El Paso for its part in alleged manipulation of natural gas and electricity commodity and transportation markets during the period from September 1996 to March 2003. Under the El Paso settlement, El Paso will pay $1.5 billion in cash and non-cash consideration, of which approximately $550 million is now in an escrow account and approximately $875 million will be paid over 15 to 20 years. Our share of the $1.5 billion settlement is approximately $300 million. El Paso also agreed to a $125 million reduction in El Paso’s long-term electricity supply contracts with the DWR, to provide pipeline capacity to California and to ensure specific reserve capacity for us, if needed. In October 2003, the CPUC approved an allocation of these refunds, under which our natural gas customers would receive approximately $80 million and our electricity customers would receive approximately $216 million. The settlement was approved by the FERC in November 2003 and by the San Diego Superior Court in December 2003. At least one appeal of the San Diego Superior Court’s approval has been filed; however, we believe that it is probable that the El Paso settlement will not be overturned on appeal. Our proposed electricity rate reduction in 2004, filed with the CPUC

on January 26, 2004, included a reduction of $79 million to the $2.21 billion after-tax regulatory asset related to this El Paso settlement. In December 2003, we also proposed a gas rate reduction related to this El Paso settlement of $29 million to be implemented in 2004.


	*Enron Settlement*

On December 23, 2003, we entered into a settlement agreement with five subsidiaries of Enron Corporation, or Enron, settling certain claims between us and Enron, or the Enron settlement. The Enron settlement will become effective if approved by the bankruptcy courts overseeing both our and Enron’s Chapter 11 proceedings. A hearing for approval of the Enron settlement is currently scheduled in our Chapter 11 proceeding on March 5, 2004. A hearing was held in the Enron bankruptcy court on February 5, 2004 and the matter was submitted. Various parties have opposed the settlement in our and Enron’s Chapter 11 proceedings. If the Enron settlement is approved, we will receive an after-tax credit of approximately $90 million that will reduce the $2.21 billion after-tax regulatory asset provided for in the settlement agreement. In the rate design settlement approved by the CPUC on February 26, 2004, our revenue requirement related to the amortization of the $2.21 billion after-tax regulatory asset has been reduced to reflect the proposed settlement. The CPUC decision approving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the amounts actually received by us under pending settlements with energy suppliers, including Enron.


	*DWR Contracts*

The DWR provided approximately 30% of the electricity delivered to our customers for the year ended December 31, 2003. The DWR purchased the electricity under contracts with various generators and through open market purchases. We are responsible for administration and dispatch of the DWR’s electricity procurement contracts allocated to our customers, for purposes of meeting a portion of our net open position. The DWR remains legally and financially responsible for its electricity procurement contracts.

The DWR contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered.

The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to us without the consent of the CPUC. The settlement agreement provides that the CPUC will not require us to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:



	•	after assumption, our issuer rating by Moody’s will be no less than A2 and our long-term issuer credit rating by S&P will be no less than A;



	•	the CPUC first makes a finding that, for purposes of assignment or assumption, the DWR power purchase contracts to be assumed are just and reasonable; and



	•	the CPUC has acted to ensure that we will receive full and timely recovery in our retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

Our Regulatory Environment

We are regulated primarily by the CPUC and the FERC. The FERC is an independent agency within the U.S. Department of Energy, or DOE, that, among other things, regulates the transmission of electricity and the sale for resale of electricity in interstate commerce. The CPUC has jurisdiction to, among other things, set the rates, terms and conditions of service for our electricity distribution, natural gas distribution and natural gas transportation and storage services in California.

Ratemaking


	*Rates*


	Transition from Frozen Rates to Cost of Service Ratemaking

Frozen electricity rates, which began on January 1, 1998, were designed to allow us to recover our authorized utility costs, and, to the extent frozen rates generated revenues in excess of these costs, to recover our transition costs. Although the surcharges implemented in 2001 effectively increased the actual rate under the frozen rate structure, increases in our authorized revenue requirements did not increase our revenues. In addition, DWR revenue requirements reduced our revenues under the frozen rate structure. As a result of revised electricity rates discussed below and a January 2004 CPUC decision determining that the rate freeze ended on January 18, 2001, we expect that once approved by the CPUC, our rates will reflect cost of service ratemaking and will be calculated based on the aggregate of various authorized rate components. Changes in any individual revenue requirement will change customers’ electricity rates.

On February 26, 2004, the CPUC approved the rate design settlement to implement an overall electricity rate reduction of approximately $799 million. Although actual rates will not be reflected in customers’ bills until March 1, 2004, or shortly thereafter, the rate reduction is retroactive to January 1, 2004. The revised rates and forecast revenue requirements are based on, and ultimately will be adjusted to reflect, pending or final CPUC decisions including:



	•	our 2003 general rate case;



	•	the allocation of the DWR’s 2004 revenue requirements;



	•	pending energy supplier refunds, claim offsets or other credits pursuant to the settlement agreement; and



	•	the calculation of any overcollection of the surcharge revenues for 2003.


	General Rate Case Settlement

The CPUC determines the amount of authorized base revenues we can collect from customers to recover our basic business and operational costs for electricity and natural gas distribution operations and for electricity generation operations in a general rate case. Our last general rate case was our 1999 general rate case, approved by the CPUC in 2000. The 2003 general rate case has been filed, testimony has been given before the CPUC and we are awaiting a final decision. Any revenue requirement change resulting from a final decision will be retroactive to January 1, 2003.

In July 2003, we and various intervenors (the CPUC’s Office of Ratepayer Advocates, or ORA, TURN, Aglet Consumer Alliance, and the City and County of San Francisco) filed a joint motion with the CPUC seeking approval of a settlement agreement resolving specific issues related to the cost of operating our electricity generation facilities, or the generation settlement. In September 2003, we and various intervenors (ORA, TURN, Aglet Consumer Alliance, the Modesto Irrigation District, the Natural Resources Defense Council and the Agricultural Energy Consumers Association) filed a joint motion with the CPUC seeking approval of the general rate case settlement. The general rate case settlement, together with the generation settlement, resolves all disputed economic issues among the settling parties related to our electricity distribution, natural gas distribution and generation revenue requirements, with the exception of our request that the CPUC include the costs of a pension contribution in our revenue requirement. The CPUC will resolve the pension contribution issue, as well as other issues raised by non-settling intervenors, in its final decision. The CPUC agreed in the settlement agreement to act promptly on the 2003 general rate case.

The general rate case settlement would result in a total 2003 revenue requirement of approximately $2.5 billion for electricity distribution operations, representing an increase of approximately $236 million in our electricity distribution revenue requirement over the current authorized amount. The general rate case settlement provides that the electricity distribution rate base on which we would be entitled to earn an authorized rate of return would be approximately $7.7 billion, based on recorded 2002 plant, and including net weighted average capital additions for 2003 of approximately $292 million.

The general rate case settlement also would result in a total 2003 revenue requirement of approximately $927 million for our natural gas distribution operations, representing an increase of approximately $52 million in our natural gas distribution revenue requirement over the current authorized amount. The general rate case settlement also provides that the amount of natural gas distribution rate base on which we would be entitled to earn an authorized rate of return would be approximately $2.1 billion, based on recorded 2002 plant and including weighted average capital additions for 2003 of approximately $89 million.

Together with the generation settlement, the general rate case settlement would result in a 2003 generation revenue requirement of $912 million representing an increase of approximately $38 million in our generation revenue requirement over the current authorized amount. This generation revenue requirement excludes fuel expense, the cost of electricity purchases, the DWR revenue requirements and nuclear decommissioning revenue requirements. Under the settlement agreement, our adopted 2003 generation rate base of approximately $1.6 billion would be deemed just and reasonable by the CPUC and not subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. This reaffirmation of our electricity generation rate base would allow recognition of an after-tax regulatory asset of approximately $800 million (or approximately $1.3 billion pre-tax) as estimated at December 31, 2003. We expect to record this regulatory asset when it meets the probability requirements for regulatory recovery in rates as provided for in SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” or SFAS No. 71, as discussed above. The individual components of the regulatory asset will be amortized over their respective lives. The weighted average life of these individual components is approximately 16 years.

The general rate case settlement also provides for new balancing accounts to be established retroactive to January 1, 2004 that permit us to recover our authorized electricity distribution and generation revenue requirement regardless of the level of sales. If sales levels do not generate the full revenue requirement in a period, rates in subsequent periods will be increased to collect the shortfall. Similarly, future rates will decrease if sales levels generate more than the full revenue requirement.

If we prevail on the pension contribution issue, an additional revenue requirement of approximately $75 million would be allocated among electricity distribution, natural gas distribution and electricity generation operations.

Because the CPUC has yet to issue a final decision on our 2003 general rate case, we have not included the natural gas distribution revenue requirement increase in our 2003 results of operations. If the CPUC approves a 2003 revenue requirement increase in 2004, we would record both the 2003 and 2004 natural gas distribution revenue requirement increase in our 2004 results of operations.

In 2003 we collected electricity revenue and surcharges subject to refund under the frozen rate structure. The amount of electricity revenue subject to refund pursuant to the rate design settlement in 2003 was $125 million, which incorporates the impact of the electric portion of the general rate case settlement. We have recorded a regulatory liability for such amount. If the revenue requirement that is ultimately approved in our 2003 general rate case is lower than the amounts described above, the regulatory liability would increase.

The CPUC also is considering a proposed reliability performance incentive mechanism for us that would be in effect from 2004 through 2009. Under the proposed incentive mechanism, we would receive up to $27 million in additional annual revenues to be recorded in a one-way balancing account to be spent exclusively on reliability performance activities with a goal of decreasing the duration and frequency of electricity outages. We would be entitled to earn a maximum reward of up to $42 million each year depending on the extent to which we exceeded the reliability performance improvement targets. Conversely, we would be required to pay a penalty of up to $42 million a year depending on the extent to which we failed to meet the target.

On February 3, 2004, the CPUC reopened the 2003 general rate case record for the purpose of taking further evidence regarding executive compensation and bonuses. We have filed a report addressing these issues with the CPUC. We are uncertain how this matter will be resolved and when a final general rate case decision will be issued.

If the general rate case settlement is not approved by the CPUC, our ability to earn our authorized rate of return for the years until the next general rate case would be adversely affected. The parties to the general rate

case settlement have agreed that our next general rate case will determine rates for test year 2007. We are unable to predict the outcome of the 2003 general rate case or the impact it will have on our financial condition or results of operations.


	Attrition Rate Adjustments for 2004-2006

The general rate case settlement provides for yearly adjustments to our base revenues, or attrition increases, for the years 2004, 2005 and 2006. The attrition increase will be based upon the change in the consumer price index, or CPI, subject to certain minimums and maximums.

The following tables show the multiplier, and the minimum and maximum percentage change for each revenue requirement along with estimates of the minimum and maximum total electricity distribution, natural gas distribution and generation revenue requirements for the years that would be covered by the 2003 general rate case.


	2004	2005	2006

Minimum	2.00% Distribution	2.25% Distribution	3.00% Distribution
	1.50% Generation	1.50% Generation	2.50% Generation
Multiplier	Change in CPI	Change in CPI	Change in CPI + 1%
Maximum	3.00% Distribution	3.25% Distribution	4.00% Distribution
	3.00% Generation	3.00% Generation	4.00% Generation


		2003		2004		2005		2006


		(in billions)
Electric Distribution Revenues		$	2.493
	Minimum			$	2.543	$	2.600	$	2.678
	Maximum				2.568		2.651		2.757
Gas Distribution Revenues			0.927
	Minimum				0.946		0.967		0.996
	Maximum				0.955		0.986		1.025
Generation Revenues (1)			0.912
	Minimum				0.926		0.940		0.963
	Maximum				0.939		0.968		1.006


(1)	Generation calculations exclude an approximately $32 million incremental attrition adjustment in 2004 to reflect the need for a second refueling outage at the Diablo Canyon power plant during that year.

Because these attrition adjustments are based on our current authorized capital structure and rate of return, they could be affected by future cost of capital proceedings. In addition, if we prevail on the pension contribution issue as discussed above, the attrition adjustments would be slightly higher to reflect the addition of approximately $75 million to our 2003 revenue requirements.


	Cost of Capital Proceedings

Each year we must file an application with the CPUC to determine our authorized capital structure and the authorized rate of return we may earn on our electricity and natural gas distribution and electricity generation assets. For our electricity and natural gas distribution operations and electricity generation operations, our currently authorized return on equity is 11.22% and our currently authorized cost of debt is 7.57%. Our currently authorized capital structure is 48.00% common equity, 46.20% long-term debt and 5.80% preferred equity.

We must file a cost of capital application within 30 days after completing the financings to implement our plan of reorganization. For 2004, this cost of capital proceeding will also determine the authorized rate of return for natural gas transportation and storage. The application must reflect changes in capital structure, long-term debt and preferred stock costs and costs associated with interest rate hedges. The settlement agreement provides that from January 1, 2004 until Moody’s has issued an issuer rating for us of not less than A3 or S&P has issued a long-term issuer credit rating for us of not less than A–, our authorized return on equity will be no less than 11.22% per year and our authorized equity ratio will be no less than 52%. However, for 2004 and 2005, our

authorized equity ratio will equal the greater of the proportion of equity approved in our 2004 and 2005 cost of capital proceedings and 48.6%.

DWR Revenue Requirements

The DWR filed a proposed $4.5 billion 2004 power charge revenue requirement and a proposed 2004 bond charge revenue requirement of approximately $873 million with the CPUC in September 2003. In January 2004, the CPUC issued a decision that adopted an interim allocation of the DWR’s proposed 2004 revenue requirements among the three California investor-owned electric utilities. Our customers’ share of the DWR power charge revenue requirement is approximately $1.8 billion after consideration of the DWR 2001-2002 adjustment discussed below. The January 2004 decision allocated the bond charge revenue requirement among the three California investor-owned electric utilities on an equal cents per kWh basis, which resulted in approximately $369 million being allocated to our customers.

The CPUC will consider adopting a multi-year allocation of the DWR’s power charge revenue requirements in a second phase of the 2004 DWR power charge proceeding. If adopted, a multi-year allocation would replace the interim allocation for 2004. We cannot predict the final outcome of this matter.

The DWR revenue requirements have been subject to various adjustments, including the reallocation of contracts among the California investor-owned electric utilities, adjustments to reflect actual deliveries and adjustments resulting from changes in allocation methodologies. In January 2004, the CPUC issued a decision finding that we had over-remitted approximately $101 million in power charges to the DWR related to the DWR’s 2001-2002 revenue requirement and ordered that our allocation of the DWR’s 2004 power charge revenue requirement be reduced by this amount.

As a result of the transition from frozen rates to cost of service ratemaking described above, the collection of DWR revenue requirements, or any adjustments to DWR revenue requirements, including the reduction in the DWR’s 2004 revenue requirement related to 2001 through 2002, will not affect our results of operations.

Baseline Allowance Increase

In May 2002, the CPUC ordered the California investor-owned electric utilities to increase the baseline allowances for certain residential customers, which reduced our electricity revenues. An increase to a customer’s baseline allowance is an increase to the amount of monthly usage that is covered under the lowest possible electricity rate and exempt from certain surcharges. The CPUC deferred consideration of corresponding rate changes until a later phase of the proceeding and ordered the California investor-owned electric utilities to track the undercollections associated with their respective baseline quantity changes in an interest-bearing balancing account. We are charging the electricity revenue-related shortfall against earnings because we cannot predict the outcome of the later phase of the proceeding, nor can we conclude that recovery of the electricity-related balancing account is probable. The total electricity revenue shortfall was approximately $70 million for the period from May through December 2002 and approximately $114 million for 2003. On February 26, 2004, the CPUC issued a decision which includes demographic revisions to the baseline program. These modifications increase annual electricity revenue shortfalls by approximately $12 million. The rate design settlement, approved by the CPUC on February 26, 2004, provides for timely rate adjustments for prospective revenue shortfalls resulting from the baseline program. The rate design settlement does not, however, provide for the recovery of shortfalls before the implementation of the rate design settlement.

Electricity Procurement

Our Electricity Procurement

Beginning January 1, 2003, we resumed responsibility for procuring electricity for our residual net open position. Our residual net open position is expected to grow over time for a number of reasons, including:



	•	Periodic expirations of existing electricity purchase contracts.



	•	Periodic expirations or other terminations of the DWR allocated contracts. For the period 2004-2009, the DWR must-take contracts and contracts with mandatory capacity payments are expected to supply about



		25% of the electricity demands of our customers. For the period 2010-2012, the DWR must-take contracts and contracts with mandatory capacity payments are expected to supply less than 10% of the electricity demands of our customers.



	•	Increases in our customers’ electricity demands due to customer and economic growth or other factors.



	•	Retirement or closure of our electricity generation facilities.

In addition, unexpected outages at our Diablo Canyon power plant, or any of our other significant generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase our residual net open position.

Effective January 1, 2003, under California law we established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the recorded procurement revenues and actual costs incurred under our authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an investor-owned utility’s electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate, when the aggregate overcollections or undercollections exceed 5% of the utility’s prior year electricity procurement revenues, excluding amounts collected for the DWR. These mandatory adjustments will continue until January 1, 2006. The CPUC’s review of our procurement activities will examine our least-cost dispatch of our resource portfolio (including the DWR allocated contracts), fuel expenses for our electricity generation facilities, contract administration (including administration of the DWR allocated contracts) and our electricity procurement contracts. As a result of this review, some of our procurement costs could be disallowed. We cannot predict whether a disallowance will occur or the size of any potential disallowance.

In January 2004, the CPUC adopted an interim decision that would require the California investor-owned electric utilities to achieve by January 1, 2008 an electricity reserve margin of 15-17% in excess of peak capacity electricity requirements and have a diverse portfolio of electricity sources. These requirements may increase our residual net open position. Specific procedures contained in the decision relating to development and execution of our procurement plans may also cause our cost of electricity to increase. The CPUC also continued its target of a 5% limitation on reliance by the California investor-owned electric utilities on the spot market to meet their energy needs.

In February 2004, we requested that the CPUC approve our 2004 ERRA revenue requirement of approximately $2.2 billion associated with our 2004 short-term procurement plan. Costs associated with electricity procurement contracts entered into prior to January 1, 2003, such as the qualifying facility contracts, are eligible for recovery under the ERRA provided the costs are under a CPUC authorized benchmark. The benchmark anticipated to be adopted by the CPUC for 2004 is $0.0518 per kWh, based upon a report prepared by the California Energy Commission, or CEC. The CPUC will establish a benchmark for each year of the ERRA. Determination of whether procurement costs associated with these contracts are within the benchmark is done on a portfolio basis including a hypothetical cost for our own generation facilities. Costs that are above the benchmark are recoverable as above-market generation and procurement costs. We have asked the CPUC to approve an additional proposed revenue requirement of approximately $150 million to recover the 2004 costs related to the above-market generation and procurement costs that exceed the CPUC-adopted benchmark discussed above.

On February 26, 2004, the CPUC approved revised rates based on our overall revenue requirements for 2004 included in a filing we made on January 26, 2004. If related filings are approved by the CPUC, the ERRA would track and allow recovery of the difference between actual ERRA revenues collected and actual costs incurred.

Although the CPUC has no authority to review the reasonableness of procurement costs in the DWR’s contracts, it may review our administration of the DWR allocated contracts. We are required to dispatch our electricity resources, including the DWR allocated contracts, on a least-cost basis. The CPUC has established a maximum annual procurement disallowance for our administration of the DWR allocated contracts and least-cost dispatch of our electricity resources of two times our administration costs of managing procurement activities, or $36 million for 2003. Activities excluded from the maximum annual disallowance include fuel expenses for

our electricity generation resources and contract administration costs associated with electricity procurement contracts, qualifying facility contracts and certain electricity generation expenses. In its decision approving our 2004 short-term procurement plan, the CPUC extended the application of this maximum disallowance amount to cover our 2004 procurement activities. It is uncertain whether the CPUC will modify or eliminate the maximum annual disallowance for future years.

FERC Prospective Price Mitigation Relief

Various entities, including the state of California and us, are seeking up to $8.9 billion in refunds on behalf of California electricity purchasers for electricity overcharges from January 2000 to June 2001. In December 2002, a FERC administrative law judge issued an initial decision finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001 (the only time period for which the FERC permitted refund claims), but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

During 2003, the FERC confirmed most of the administrative law judge’s findings, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the PX, which operates solely to reconcile remaining refund amounts owed, to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by August 2004. The actual refunds will not be determined until the FERC issues a final decision following the ISO and PX compliance filings. The FERC is uncertain when it will issue a final decision in this proceeding. In addition, future refunds could increase or decrease as a result of an alternative calculation proposed by the ISO, which incorporates revised data provided by us and other entities.

Under the settlement agreement, we and Corp agreed to continue to cooperate with the CPUC and the state of California in seeking refunds from generators and other energy suppliers. The net after-tax amount of any refunds, claim offsets or other credits from generators and other energy suppliers relating to our ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offset of creditor claims in our Chapter 11 proceeding would reduce the balance of the $2.21 billion after-tax regulatory asset created by the settlement agreement.

We have recorded approximately $1.8 billion of claims filed by various electricity generators in our Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. We currently estimate that the claims filed would have been reduced to approximately $1.2 billion based on the refund methodology recommended in the administrative law judge’s initial decision, resulting in a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset. The recalculation of market prices according to the revised methodology adopted by the FERC in its October 2003 decision could further reduce the amount of the suppliers’ claims by several hundred million dollars. However, this reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology.

FERC Transmission Owner Rate Cases

On January 13, 2003, we filed an application with the FERC requesting authority to recover approximately $545 million in annual electricity transmission retail revenue requirements for 2003. The January 13, 2003 proposed rates went into effect, subject to refund, on August 13, 2003 and remained in effect through December 31, 2003. We have accrued approximately $26 million for potential refunds related to the period these rates were in effect.

We filed an additional rate application with the FERC at the end of October 2003 requesting recovery of approximately $530 million per year, subject to refund, in electricity transmission retail revenue requirements. We requested a 13.0% return on equity and recovery of the costs of providing safe and reliable transmission

service during 2004. On December 30, 2003 the FERC accepted this proposed revenue requirement and related rates, subject to hearing and refund, effective as of January 1, 2004.


	*Natural Gas Supply and Transportation*

In 1998, we implemented a ratemaking pact called the gas accord under which the natural gas transportation and storage services we provide were separated for ratemaking purposes from our distribution services. On December 18, 2003, the CPUC approved our application to retain the gas accord market structure for 2004 and 2005 and resolved the rates, and terms and conditions of service for our natural gas transportation and storage system for 2004. The CPUC adopted a 2004 revenue requirement of $436.4 million, representing a $12.5 million increase from 2003.

In addition, the December 2003 CPUC decision exempts, beginning in 2005, certain customers connected to our backbone transportation facilities from paying local transportation rates and orders us to review and consider a backbone level rate structure, which may include a surcharge to recover what may otherwise be stranded costs resulting from departing local transmission customers. Our backbone transportation facilities connect natural gas transportation pipelines delivering natural gas from California’s border and from California production and storage facilities to the local natural gas transportation system.

Under the gas accord market structure, we are at risk of not recovering our natural gas transportation and storage costs and do not have regulatory balancing account provisions for overcollections or undercollections of natural gas transportation or storage revenues. We may experience a material reduction in operating revenues if throughput levels or market conditions are significantly less favorable than reflected in rates for these services.

The gas accord also established an incentive mechanism for recovery of core procurement costs, or the CPIM, which is used to determine the reasonableness of our costs of purchasing natural gas for our customers. The December 2003 CPUC decision extended the CPIM with adjustments through 2005. Under the CPIM, our purchase costs are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where we typically purchases natural gas. Costs that fall within a tolerance band, which is currently 99% to 102% of the benchmark, are considered reasonable and fully recoverable in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in our customers’ rates, and our customers receive three-fourths of the savings when the costs are below 99% of the benchmark.

On January 22, 2004, the CPUC opened a rulemaking to require California natural gas utilities to submit proposals aimed at ensuring reliable, long-term supplies of natural gas to California. The CPUC ordered us and other California natural gas utilities to submit proposals addressing how California’s long-term natural gas needs should be met through contracts with interstate pipelines, new liquified natural gas facilities, storage facilities and in-state production of natural gas. This proceeding will be divided into two phases. Phase 1 will address utilities’ expiring contracts with interstate pipelines, the amount of interstate capacity the utilities should hold, the approval process for contracts with interstate pipelines and access to liquified natural gas facilities supplies. Phase 2 will examine broader long-term supply and capacity issues. We are unable to predict the outcome of this rulemaking or the impact it will have on our financial condition or results of operations.


	*Annual Earnings Assessment Proceeding for Energy Efficiency Program Activities and Public Purpose Programs*

In May 2003, 2002, 2001 and 2000, we filed our annual applications with the CPUC in the Annual Earnings Assessment Proceeding claiming incentives totaling approximately $106 million for energy efficiency program activities and public purpose programs. These applications remain subject to verification and approval by the CPUC. The CPUC has only authorized us to recognize an insignificant amount of these incentives in our consolidated statements of operations. There are a number of forward-looking proceedings regarding program administration and incentive mechanisms for energy efficiency. It is too early to predict whether the CPUC will allow us to continue administering energy efficiency programs and earning incentives based on the performance of the programs.


	*2001 Annual Transition Cost Proceeding: Review of Reasonableness of Electricity Procurement*

In April 2003, the ORA issued a report regarding our procurement activities for the period July 1, 2000 through June 30, 2001, recommending that the CPUC disallow recovery of approximately $434 million of our procurement costs based on an allegation that our market purchases during the period were imprudent because we did not develop and execute a reasonable hedging strategy. The ORA recommendation does not take into account any FERC-ordered refunds of our procurement costs during this period, which could effectively reduce the amount of the recommended disallowance. In our response to the ORA’s report, we indicated that the ORA recommendation is unlawful, contrary to prior CPUC decisions, and factually unsupported. Under the settlement agreement, the CPUC agreed to act promptly to resolve this proceeding, with no adverse impact on our cost recovery, as soon as practicable after our plan of reorganization becomes effective.

Critical Accounting Policies

The preparation of consolidated financial statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies due, in part, to their complexity and because their application is relevant and material to our financial position and results of operations, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.


	*DWR Revenues*

We act as a pass-through entity for electricity purchased by the DWR that is sold to our customers. Although charges for electricity provided by the DWR are included in the amounts we bill our customers, we deduct from electricity revenues amounts passed through to the DWR. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers, priced at the related CPUC-approved remittance rate. These pass-through amounts are excluded from our electricity revenues in our consolidated statements of operations. During 2003, 2002 and 2001, the pass-through amounts have been subject to significant adjustments.

On February 26, 2004, the CPUC approved revised electricity rates reflected in the rate design settlement to implement an overall electricity rate reduction of approximately $799 million. Although actual rates will not be reflected in customers’ bills until March 1, 2004, or shortly thereafter, the rate reduction is retroactive to January 2004. Because the DWR’s revenue requirements will be included as a component of our total rates in 2004, any difference between the actual DWR revenue requirements and those assumed in the rate design settlement will result in an adjustment of our electricity rates. Any adjustments that occur are not expected to impact our future results of operations or financial position.

The DWR’s revenue requirements are subject to various adjustments, including the reallocation of DWR contracts among the California investor-owned electric utilities, adjustments to actual deliveries and changes in allocation methodologies. In January 2004, the CPUC issued a decision finding that we over-remitted approximately $101 million in power charges to the DWR related to the DWR’s 2001-2002 revenue requirement and ordered that our allocation of the DWR’s 2004 revenue requirement to the customers of the California investor-owned electric utilities be reduced by this amount.


	*Regulatory Assets and Liabilities*

We apply SFAS No. 71 to our regulated operations. Under SFAS No. 71, regulatory assets represent capitalized costs that otherwise would be charged to expense under GAAP. These costs are later recovered through regulated rates. Regulatory liabilities are created by rate actions of a regulator that will later be credited to customers through the ratemaking process. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, administrative law judge proposed decisions, final regulatory orders and the strength or

status of applications for regulatory rehearings or state court appeals. We also maintain regulatory balancing accounts, which are comprised of sales and cost balancing accounts. These balancing accounts are used to record the differences between revenues and costs that are recorded and that can be recovered through rates.

If it is determined that a regulatory asset is no longer probable of recovery in rates, then SFAS No. 71 requires that it be written off at that time. At December 31, 2003, we reported regulatory assets (including current regulatory balancing accounts receivable) of approximately $2.2 billion and regulatory liabilities (including current balancing accounts payable) of approximately $4.2 billion.

We expect to recognize the regulatory assets created by the settlement agreement when they meet the probability requirements of SFAS No. 71. Implementation of our plan of reorganization is subject to various conditions, including the consummation of the public offering of senior bonds, the receipt of investment grade credit ratings and final CPUC approval of the settlement agreement. Under the terms of our plan of reorganization, we and Corp may determine that the CPUC order approving the settlement agreement is final even if appeals are pending. There can be no assurance that the settlement agreement will not be modified on rehearing or appeal or that our plan of reorganization will become effective. Until certain conditions or events regarding the effectiveness of our plan of reorganization discussed above are resolved further, we cannot conclude that the probability requirements of SFAS No. 71 have been met and therefore cannot record the regulatory assets contemplated in the settlement agreement.


	*Unbilled Revenues*

We record revenue as electricity and natural gas are delivered. A portion of the revenue recognized has not yet been billed. Unbilled revenues are determined by factoring an estimate of the electricity and natural gas load delivered with recent historical usage and rate patterns.


	*Surcharge Revenues*

In January 2001, the CPUC authorized increases in electricity rates of $0.01 per kWh, in March 2001 of another $0.03 per kWh and in May 2001 of an additional $0.005 per kWh. The use of these surcharge revenues was initially restricted to “ongoing procurement costs” and “future power purchases.” In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the surcharges to be used to restore our financial health by permitting us to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. From January 2001 to December 31, 2003, we recognized total surcharge revenues of approximately $8.1 billion, pre-tax. The rate design settlement included a refund of approximately $125 million of surcharge revenues. We recorded a regulatory liability for the potential refund of approximately $125 million of surcharge revenues collected during 2003, which is reflected on our balance sheet at December 31, 2003. If the CPUC requires us to refund any amounts in excess of $125 million, our earnings could be materially adversely affected.


	*Environmental Remediation Liabilities*

Given the complexities of the legal and regulatory environment regarding environmental laws, the process of estimating environmental remediation liabilities is a subjective one. We record a liability associated with environmental remediation activities when it is determined that remediation is probable and our cost can be estimated in a reasonable manner. The liability can be based on many factors, including site investigations, remediation, operations, maintenance, monitoring and closure. This liability is recorded at the lower range of estimated costs, unless a more objective estimate can be achieved. The recorded liability is re-examined every quarter.

At December 31, 2003, our accrual for undiscounted environmental liability was approximately $314 million, which was approximately $17 million lower than at December 31, 2002, mainly due to a reassessment of the estimated cost of remediation and remediation payments. Our undiscounted future costs could increase to as much as $422 million if other potentially responsible parties are not able to contribute to the settlement of these costs or the extent of contamination or necessary remediation is greater than anticipated.


	*Derivatives*

In 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, or SFAS No. 133, which required all derivative instruments to be recognized in the financial statements at their fair value.

We have long-term purchase contracts, including power purchase and renewable energy, natural gas supply and transportation, and nuclear fuel as reflected in “Capital Expenditures and Commitments” discussed above. We have determined most of these contracts, including substantially all of our qualifying facility and nuclear fuel contracts, are not derivative instruments. Most of the remaining contracts that are derivative instruments are exempt from the mark-to-market requirements of SFAS No. 133 under the normal purchases and sales exception and are not reflected on the balance sheet at fair value. In addition, we hold derivative instruments that are used to offset natural gas commodity price risk and interest rate risk. These instruments qualify for cash flow hedge treatment under SFAS No. 133 and are presented on the balance sheet at fair value, which amounted to approximately $21 million at December 31, 2003.

Pension and Other Postretirement Plans

We provide qualified and non-qualified non-contributory defined benefit pension plans to our employees and retirees and certain of our affiliates’ employees and retirees. Our retired employees and certain of our affiliates’ retired employees and their eligible dependents also participate in contributory medical plans, and certain retired employees participate in life insurance plans (referred to collectively as other benefits). Amounts that we recognize as obligations to provide pension benefits under SFAS No. 87, “Employers’ Accounting for Pensions,” and other benefits under SFAS No. 106, “Employers Accounting for Postretirement Benefits other than Pensions,” are based on certain actuarial assumptions. Actuarial assumptions used in determining pension obligations include the discount rate, the average rate of future compensation increases and the expected return on plan assets. Actuarial assumptions used in determining other benefit obligations include the discount rate, the average rate of future compensation increases, the expected return on plan assets and the assumed health care cost trend rate. While we believe the assumptions used are appropriate, significant differences in actual experience, plan changes or significant changes in assumptions may materially affect the recorded pension and other benefit obligations and future plan expenses.

Pension and other benefit funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for pension and other benefit payments. Consistent with the trusts’ investment policies, assets are invested in U.S. equities, non-U.S. equities and fixed income securities. Investment securities are exposed to various risks, including interest rate, credit and overall market volatility risks. As a result of these risks, it is reasonably possible that the market values of investment securities could increase or decrease in the near term. Increases or decreases in market values could materially affect the current value of the trusts and, as a result, the future level of pension and other benefit expense.

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed income projected returns were based on historical returns for the broad U.S. bond market. Equity returns were based primarily on historical returns of the S&P 500 Index. For our Retirement Plan, the assumed return of 8.1% compares to a ten-year actual return of 8.5%.

The rate used to discount pension and other post-retirement benefit plan liabilities was based on a yield curve developed from the Moody’s AA Corporate Bond Index at December 31, 2003. This yield curve has discount rates that vary based on the maturity of the obligations. The estimated future cash flows for the pension and other post retirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. For our Retirement Plan, a decrease in the discount rate from 6.25% to 6.00% would increase the accumulated benefit obligation by approximately $202 million.

Accounting Pronouncements Issued but not Yet Adopted


	*Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003*

In January 2004, the Financial Accounting Standards Board, or FASB, issued FASB Staff Position SFAS No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” or SFAS No. 106-1. SFAS No. 106-1 permits a sponsor to make a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, or the Prescription Drug Act. The Prescription Drug Act, signed into law in December 2003, establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. SFAS No. 106-1 does not provide specific guidance as to whether a sponsor should recognize the effects of the Prescription Drug Act in its financial statements. The Prescription Drug Act introduces two new features to Medicare that must be considered when measuring accumulated postretirement benefit costs. The new features include a subsidy to the plan sponsors that is based on 28% of an individual beneficiary’s annual prescription drug costs between $250 and $5,000 and an opportunity for a retiree to obtain a prescription drug benefit under Medicare. The Prescription Drug Act is expected to reduce our net postretirement benefit costs.

We have elected to defer adoption of SFAS No. 106-1 due to the lack of specific guidance. Therefore, the net postretirement benefit costs disclosed in our consolidated financial statements do not reflect the impacts of the Prescription Drug Act on the plans. The deferral will continue to apply until specific authoritative accounting guidance for the federal subsidy is issued. Authoritative guidance on the accounting for the federal subsidy is pending and, when issued, could require information previously reported in our consolidated financial statements to change. We are currently investigating the impacts of SFAS 106-1’s initial recognition, measurement and disclosure provisions on our consolidated financial statements.


	*Change in Accounting for Certain Derivative Contracts*

In November 2003, the FASB approved an amendment to an interpretation issued by the Derivatives Implementation Group C15, (as previously amended in October 2001 and December 2001, or DIG C15), that changed the definition of normal purchases and sales for certain power contracts that contain optionality.

The implementation guidance in DIG C15 impacts certain derivative instruments entered into after June 30, 2003. Prior to this amendment to DIG C15, most of our derivative instruments have qualified for the normal purchases and sales exception. However, it is possible that new derivative instruments and certain of our derivative instruments entered into prior to July 1, 2003 will no longer qualify for normal purchases and sales treatment under the new guidelines of DIG C15. Application of the new guidance to existing derivative instruments that were eligible for the normal purchases and sales exception under the previous DIG C15 guidance will be effective in the first quarter of 2004 as a cumulative effect of a change in accounting principle. We are currently evaluating the impacts, if any, of DIG C15 on our consolidated financial statements.


	*Consolidation of Variable Interest Entities*

In December 2003, the FASB issued Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” or FIN 46R, replacing Interpretation No. 46, “Consolidation of Variable Interest Entities,” or FIN 46, which was issued in January 2003. FIN 46R was issued to replace FIN 46 and to clarify the required accounting for interests in variable interest entities. A variable interest entity is an entity that does not have sufficient equity investment at risk, or the holders of the equity instruments lack the essential characteristics of a controlling financial interest. A variable interest entity is to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity’s activities, or is entitled to receive a majority of the entity’s residual returns, or both.

We must apply the provisions of FIN 46R as of January 1, 2004. We are continuing to evaluate the impacts of FIN 46R’s initial recognition, measurement and disclosure provisions on our consolidated financial statements and are unable to estimate the impact, if any, which will result when FIN 46R becomes effective. We have

investments in unconsolidated affiliates, which are mainly engaged in the purchase of low-income residential real estate property. It is reasonably possible that we will be required to consolidate our interests in these entities as a result of the adoption of FIN 46R. At December 31, 2003, our recorded investment in these entities was approximately $21 million. As a limited partner, our exposure to potential loss is limited to our investment in each partnership.

Additional Security Measures

The NRC issued orders in 2003 regarding additional security measures for all nuclear plants, including our Diablo Canyon power plant. These orders require additional capital investment and increased operating costs. However, we do not believe these costs will have a material impact on our consolidated financial position or results of operations.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Management Activities

We are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. We face market risk associated with our operations, financing arrangements, the marketplace for electricity, natural gas, electricity transmission, natural gas transportation and storage, other goods and services, and with other aspects of our business. We categorize market risks as price risk, interest rate risk and credit risk. We actively manage market risks through risk management programs that are designed to support business objectives, reduce costs, discourage unauthorized risk, reduce earnings volatility and manage cash flows. Our risk management activities often include the use of energy and financial derivative instruments, including forward contracts, futures, swaps, options, and other instruments and agreements.

We use derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. We use derivative instruments to mitigate the risks associated with ownership of assets, liabilities, committed transactions or probable forecasted transactions. We enter into derivative instruments in accordance with approved risk management policies adopted by a risk oversight committee composed of senior officers and only after the risk oversight committee approves appropriate risk limits for each derivative instrument. The organizational unit proposing the activity must successfully demonstrate that the derivative instrument satisfies a business need and that the attendant risks will be adequately measured, monitored and controlled.

We estimate fair value of derivative instruments using the midpoint of quoted bid and asked forward prices, including quotes from customers, brokers, electronic exchanges and public indices, supplemented by online price information from news services. When market data is not available we use models to estimate fair value.

Price Risk


	*Electricity*

We rely on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts and our own electricity generation facilities. On January 1, 2003, we resumed responsibility for purchasing electricity to meet our residual net open position. We have purchased electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to one year ahead) since that date.

It is estimated that the residual net open position will increase over time for a number of reasons, including:



	•	periodic expirations of existing electricity purchase contracts;



	•	periodic expirations or other terminations of the DWR allocated contracts;



	•	increases in our customers’ electricity demands due to customer and economic growth or other factors; and



	•	retirement or closure of our electricity generation facilities.

In addition, unexpected outages at our Diablo Canyon power plant or any of our other significant generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase our residual net open position. We expect to satisfy at least some of our residual net open position through new contracts.

The settlement agreement contemplates that we will recover our reasonable costs of providing utility service, including power procurement costs. In addition, California law requires that through 2006 the CPUC review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually and adjust retail electricity rates, or order refunds when there is an undercollection or overcollection exceeding 5% of our prior year electricity procurement revenues, excluding the revenue collected on behalf of the DWR. In addition, the CPUC has established maximum annual procurement disallowance for our administration of the DWR allocated contracts and least-cost dispatch of $36 million. Adverse market price changes are not expected to impact our net income, while these cost recovery regulatory mechanisms remain in place. However, we are at risk

to the extent that the CPUC may in the future disallow transactions that do not comply with the CPUC-approved short-term procurement plan. Additionally, adverse market price changes could impact the timing of our cash flows.


	*Nuclear Fuel*

We purchase nuclear fuel for our Diablo Canyon power plant through contracts with terms ranging from two to five years. These agreements are with large, well-established international producers for our long-term nuclear fuel agreements in order to diversify our commitments and ensure security of supply.

Nuclear fuel purchases are subject to tariffs of up to 50% on imports from certain countries. Our nuclear fuel costs have not increased based on the imposed tariffs because the terms of our existing long-term contracts do not include these costs. However, once these contracts begin to expire in 2004, the costs under new nuclear fuel contracts may increase. While the cost recovery regulatory mechanisms under California law described above remain in place, adverse market changes in nuclear fuel prices are not expected to materially impact net income.


	*Natural Gas*

We enter into physical and financial natural gas commodity contracts of up to one-and-a-half years in length to fulfill the needs of our retail core customers. Changes in temperature cause natural gas demand to vary daily, monthly and seasonally. Consequently, significant volumes of gas must be purchased in the spot market. To mitigate the risk of price volatility, we enter into various financial instruments, including options that may extend for up to five months in length. Our cost of natural gas includes the cost of Canadian and interstate transportation of natural gas purchased for our core customers.

Under the CPIM, our purchase costs are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where we typically purchase natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and our customers receive three-fourths of any savings resulting from our cost of natural gas that is less than 99% of the benchmark in their rates. While this cost recovery mechanism remains in place, changes in the price of natural gas are not expected to materially impact net income.

Transportation and Storage

We currently face price risk for the portion of intrastate natural gas transportation capacity that is not used by core customers. Noncore customers contract with us for natural gas transportation and storage, along with natural gas parking and lending services. We are at risk for any natural gas transportation and storage revenue volatility. Transportation is sold at competitive market-based rates within a cost-of-service tariff framework. There are significant seasonal and annual variations in the demand for natural gas transportation and storage services. We sell most of our pipeline capacity based on the volume of natural gas that is transported by our customers. As a result, our natural gas transportation revenues fluctuate.

We use a value-at-risk methodology to measure the expected maximum daily change in the 18-month forward value of our transportation and storage portfolio. The value-at-risk provides an indication of our exposure to potential high-risk market conditions, and market opportunities for improved revenues based on price changes, high-price volatility or correlation between pricing locations. It is also an important indicator of the effectiveness of hedge strategies on a portfolio. The value-at-risk methodology is based on a 95% confidence level, which means that there is a 5% probability that the portfolio will incur a loss in value in one day at least as large as the reported value-at-risk. The one-day liquidation period assumption of the value-at-risk methodology does not match the longer-term holding period of our transportation and storage contract portfolio.

Our value-at-risk for our transportation and storage portfolio was approximately $4.2 million at December 31, 2003 and approximately $4 million at December 31, 2002. Our high, low and average transportation and storage value-at-risk during 2003 was approximately $12.8, $1.7 and $5.4 million, respectively.

Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, volumetric risk, inadequate indication of the exposure of a portfolio to extreme price movements and the inability to address the risk resulting from intra-day trading activities.

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. Specific interest rate risks for us include the risk of increasing interest rates on variable rate obligations.

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2003, if interest rates changed by 1% for all current variable rate debt held by us, the change would affect net income by an immaterial amount, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

As discussed above, we plan to issue a significant portion of the senior bonds and establish credit and accounts receivable facilities to facilitate payment of allowed claims in our Chapter 11 proceeding. We entered into derivative instruments, which expire in June 2004, to partially hedge the interest rate risk on up to $7.4 billion of the long-term debt to be issued.

The hedges are reflected on our balance sheet at fair value in other current assets. The cost of the hedges, purchased at fair value, was approximately $45 million. The fair value of the hedges at December 31, 2003 was approximately $17 million. At December 31, 2003, a hypothetical 1% decrease in interest rates would cause the fair value of the interest rate hedges to fall below $1 million; however, the change in fair value of the interest rate hedges would primarily be reported in regulatory accounts, and would be offset by changes in interest expense once the forecasted debt is issued.

Credit Risk

Credit risk is the risk of loss that we would incur if customers or counterparties failed to perform their contractual obligations.

We had gross accounts receivable of approximately $2.5 billion at December 31, 2003 and approximately $2.0 billion at December 31, 2002. The majority of the accounts receivable are associated with our residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately $68 million at December 31, 2003 and approximately $59 million at December 31, 2002 were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. We have a regional concentration of credit risk associated with our receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not considered likely.

We manage credit risk for our largest customers and counterparties by assigning credit limits based on an evaluation of their financial condition, net worth, credit rating and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure for our largest customers and counterparties is calculated daily. If exposure exceeds the established limits, we take immediate action to reduce the exposure or obtain additional collateral, or both. Further, we rely heavily on master agreements that require security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

We calculate gross credit exposure for each of our largest customers and counterparties as the current mark-to-market value of the contract (i.e., the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, before the application of credit collateral. During 2003, we recognized no material losses due to contract defaults or bankruptcies. At December 31, 2003, there were three

counterparties that represented greater than 10% of our net credit exposure. We had two investment grade counterparties that represented a total of approximately 32% of our net credit exposure and one below-investment grade counterparty that represented approximately 12% of our net credit exposure.

We conduct business with customers or vendors mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. This concentration of counterparties may impact our overall exposure to credit risk because counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions.

DESCRIPTION OF OUR PLAN OF REORGANIZATION

Background

In 1998, the state of California implemented electricity industry restructuring and established a framework allowing generators and other power providers to charge market-based prices for electricity sold on the wholesale market. The implementing legislation also established a retail electricity rate freeze and a plan for recovering our generation-related costs that were expected to be uneconomic under the new market framework. State regulatory action further required us to divest a majority of our fossil fuel-fired generation facilities and made it economically unattractive to retain our remaining generation facilities. The resulting sales of generation facilities in turn made us more dependent on the newly deregulated wholesale electricity market.

Beginning in May 2000, wholesale prices for electricity began to increase. Since our retail electricity rates remained frozen, we financed the higher costs of wholesale electricity by issuing debt and drawing on our credit facilities. Our inability to recover our electricity purchase costs from customers ultimately resulted in billions of dollars in defaulted debt and unpaid bills and caused us to file a voluntary petition for relief under Chapter 11 on April 6, 2001. Pursuant to Chapter 11, we have retained control of our assets and are authorized to operate our business as a debtor-in-possession while subject to the jurisdiction of the bankruptcy court.

The CPUC Settlement Agreement

On December 19, 2003, we, Corp and the CPUC entered into the settlement agreement that contemplates a new plan of reorganization to supersede the competing plans.

In the settlement agreement, we and Corp agreed that we would remain a vertically integrated utility primarily under CPUC regulation. The settlement agreement allows for resolution of our Chapter 11 proceeding on terms that will permit us to emerge from Chapter 11 as an investment grade-rated company with investment grade-rated debt (at least Baa3 by Moody’s and at least BBB- by S&P), and pay in full all our valid creditor claims, plus applicable interest.

The settlement agreement contains a statement of intent that it is in the public interest to restore us to financial health and to maintain and improve our financial health in the future to ensure that we are able to provide safe and reliable electricity and natural gas service to our customers at just and reasonable rates. In addition, the settlement agreement includes a statement of intent that it is fair and in the public interest to allow us to recover, over a reasonable time, our prior uncollected costs and to provide the opportunity for our shareholders to earn a reasonable rate of return on our business. Under the settlement agreement, we will release claims against the CPUC that we or Corp would have retained under the plan of reorganization we proposed in September 2001.

On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the settlement agreement on the basis that the settlement agreement does not comply with California law. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. No additional party may request rehearings or make appeals of the CPUC’s approval of the settlement agreement. We cannot predict the timing or outcome of the requests for rehearing or any appeals.


	*Principal Terms*


	Regulatory Asset



	•	The CPUC agreed to establish a $2.21 billion after-tax regulatory asset (which is equivalent to an approximately $3.7 billion pre-tax regulatory asset) as a new, separate and additional part of our rate base that will be amortized on a “mortgage-style” basis over nine years beginning January 1, 2004. The regulatory asset will be fully amortized by the end of 2012.



	•	The CPUC also has agreed to authorize us to establish a tax tracking account, to be used if we must pay income tax on the regulatory asset before it is fully amortized, to record the difference between taxes on the regulatory asset plus interest imposed by federal or state tax authorities for earlier recognition and taxes that would have been incurred on account of the regulatory asset had it been taxed during the amortization period. The tax tracking account would earn the authorized rate of return and be amortized into rates over the longer of the remaining life of the regulatory asset or five years.



	•	The net after-tax amount of any refunds, claim offsets or other credits we receive from energy suppliers relating to specified procurement costs incurred during the California energy crisis, including from the El Paso settlement related to electricity refunds, but not natural gas refunds, will reduce the outstanding balance of the $2.21 billion after-tax regulatory asset and the related amortization. On February 26, 2004, the CPUC approved the rate design settlement which set a revenue requirement reflecting a reduction of this regulatory asset by approximately $179 million for certain of these matters.



	•	The unamortized balance of the $2.21 billion after-tax regulatory asset will earn a rate of return on its equity component of no less than 11.22% annually for its nine-year term and, after the equity component of our capital structure reaches 52%, the authorized equity component of this regulatory asset will be no less than 52% for the remaining term. The rate of return on the $2.21 billion after-tax regulatory asset would be eliminated if we complete the refinancing discussed below. Instead, we would collect from customers amounts sufficient to service the securitized debt.


	Ratemaking Matters


	•	Our adopted 2003 electricity generation rate base of $1.6 billion was deemed just and reasonable by the CPUC and not subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. This reaffirmation of our electricity generation rate base allows recognition of an after-tax regulatory asset of approximately $800 million (which is equivalent to approximately $1.3 billion pre-tax).


	•	The CPUC will timely act upon our applications to collect in rates prudently incurred costs of (including return of and return on) any new, reasonable investment in utility plant and assets. The CPUC will promptly adjust our rates consistent with Senate Bill 1976, or SB 1976, and the CPUC’s 2002 agreement with the DWR regarding establishment of the DWR’s revenue requirements to ensure that we collect in our rates our fixed amounts to service existing rate reduction bonds, regulatory asset amortization and return, and our base revenue requirements (e.g., electricity and natural gas distribution, our rate base for our electricity generation, gas commodity procurement, existing qualifying facility contract costs and associated return). The settlement agreement provides that the CPUC will not discriminate against us because of our Chapter 11 proceeding, our federal lawsuit against the CPUC commissioners to recover our previously incurred costs of providing electricity service from ratepayers under the federal filed rate doctrine, the settlement agreement, the $2.21 billion after-tax regulatory asset or any other matters addressed in or resolved by the settlement agreement.



	•	The CPUC agreed in the settlement agreement to maintain our retail electricity rates at their pre-existing levels through the end of 2003. Effective January 1, 2004, the CPUC may adjust our retail electricity rates prospectively consistent with the settlement agreement, our plan of reorganization, the confirmation order and California law. The settlement agreement includes a statement of intent that under the settlement agreement and our plan of reorganization, retail electricity rates will be reduced effective January 1, 2004 with further reductions expected thereafter.



	•	The CPUC will set our capital structure and authorized return on equity in our annual cost of capital proceedings in its usual manner. However, from January 1, 2004 until Moody’s has issued an issuer rating for us of not less than A3 or S&P has issued a long-term issuer credit rating for us of not less than A-, our authorized return on equity will be no less than 11.22% per year and our authorized equity ratio for ratemaking purposes will be no less than 52%, except that for 2004 and 2005, our authorized equity ratio will equal the greater of the proportion of equity in the forecast of our average capital structure for calendar years 2004 and 2005 filed in our cost of capital proceedings and 48.6%.



	•	The CPUC also agreed to act promptly on certain of our pending ratemaking proceedings, including our pending 2003 general rate case. The outcome of these proceedings may result in the establishment of additional regulatory assets on our consolidated balance sheet.


	California Department of Water Resources Contracts

The settlement agreement provides that the CPUC will not require us to accept an assignment of, or assume legal or financial responsibility for, the DWR power purchase contracts, unless each of the following conditions has been met:



	•	after assumption, our issuer credit rating by Moody’s will be no less than A2 and our long-term issuer credit rating from S&P will be no less than A;



	•	the CPUC first makes a finding that, for purposes of assignment or assumption, the DWR power purchase contracts to be assumed are just and reasonable; and



	•	the CPUC has acted to ensure that we will receive full and timely recovery in our retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed over their lives without further review.

Under the settlement agreement, the CPUC retains and, after any assumption of the DWR contracts, will retain the right to review the prudence of our administration and dispatch of the DWR contracts consistent with applicable law.


	Headroom

The CPUC agreed and acknowledged that the headroom, surcharge and base revenues accrued or collected by us through and including December 31, 2003 are the property of our Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in our Chapter 11 proceeding, have been included in our retail electricity rates consistent with state and federal law and are not subject to refund. The settlement agreement defines headroom as our total net after-tax income reported under GAAP, less earnings from operations (a non-GAAP financial measure that has been historically reported by Corp in its earnings press release), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided that the calculation reflects the outcome of our 2003 general rate case. The settlement agreement provides that if headroom revenue accrued by us during 2003 is greater than $875 million, pre-tax, we will refund the excess to ratepayers.


	Dismissal of Filed Rate Case, Other Litigation and Proceedings


	•	On or as soon as practicable after the later of the effective date of our plan of reorganization or the date on which CPUC approval of the settlement agreement is no longer subject to appeal, we will dismiss with prejudice the case described in the section of this prospectus titled “Business — Legal Proceedings — Pacific Gas and Electric Company vs. Michael Peevey, et al.” (addressing the federal filed rate doctrine), withdraw the original plan of reorganization and dismiss certain other pending proceedings. In exchange, on or before January 1, 2004, the CPUC would establish and authorize the collection of the regulatory asset and our rate base for our electricity generation, and, on or as soon as practicable after the effective date, resolve phase 2 of the pending annual transition cost proceeding in which the CPUC is reviewing the reasonableness of our energy crisis purchase costs, with no adverse impact on our cost recovery as filed.


	•	On or as soon as practicable after the later of the effective date of our plan of reorganization or the date on which CPUC approval of the settlement agreement is no longer subject to appeal, we, Corp and the CPUC will execute mutual releases and dismissals with prejudice of specified claims, actions or regulatory proceedings arising out of or related in any way to the energy crisis or the implementation of AB 1890, including the CPUC’s investigation into past holding company actions during the California energy crisis (but only as to past actions, not prospective matters).


	Withdrawal of Applications in Connection with the September 2001 Plan of Reorganization

As required by the settlement agreement, we have requested a stay of all proceedings before the FERC, the NRC, the SEC and other regulatory agencies relating to approvals sought to implement the plan of reorganization we proposed in September 2001. We have also suspended all actions to obtain or transfer licenses, permits and franchises to implement the proposed plan of reorganization. On the effective date of our plan of reorganization or as soon thereafter as practicable, we and Corp will withdraw or abandon all applications for these regulatory approvals. In addition, we and Corp agreed that for the life of the regulatory asset neither we nor Corp, nor our respective affiliates or subsidiaries, will make any filings under Sections 4, 5 or 7 of the Natural Gas Act to transfer ownership or ratemaking jurisdiction over our intrastate gas pipeline and storage facilities, which means that they will remain primarily subject to CPUC regulation. We and Corp also agreed that the CPUC has jurisdiction to review and approve any proposal to dispose of our property necessary or useful in the performance of our duties to the public.


	Environmental Measures

We agreed to implement the following three environmental enhancement measures:


	•	we will encumber with conservation easements or donate approximately 140,000 acres of land to public agencies or non-profit conservation organizations;


	•	we will establish a California non-profit corporation to oversee the environmental enhancements associated with these lands and fund it with $100 million in cash over ten years, although we will be entitled to recover these payments in rates; and



	•	we will establish a California non-profit corporation funded with $30 million in cash payable by us over five years, with no recovery of these payments in rates, dedicated to support research and investment in clean energy technology, primarily in our service territory.

Of the approximately 140,000 acres referred to in the first bullet, approximately 44,000 acres may be either donated or encumbered with conservation easements. The remaining land contains our or a joint licensee’s hydroelectric generation facilities and may only be encumbered with conservation easements.


	Waiver of Sovereign Immunity

The CPUC agreed to waive all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties’ rights under, the settlement agreement, our plan of reorganization or the confirmation order. The CPUC also consented to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the bankruptcy court. The CPUC’s waiver is irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off or any other legal process with respect to the enforcement of, or other determination of the parties’ rights under, the settlement agreement, our plan of reorganization or the confirmation order. The settlement agreement contemplates that neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties’ rights under the settlement agreement, our plan of reorganization or the confirmation order.


	Term and Enforceability

The settlement agreement generally terminates nine years after the effective date of our plan of reorganization, except that the rights of the parties to the settlement agreement that vest on or before termination, including any rights arising from any default under the settlement agreement, will survive termination for the purpose of enforcement. The parties agreed that the bankruptcy court will have jurisdiction over the parties for all purposes relating to enforcement of the settlement agreement, our plan of reorganization and the confirmation order. The parties also agreed that the settlement agreement, our plan of reorganization or any order entered by the bankruptcy court contemplated or required to implement the settlement agreement or our plan of reorganization will be irrevocable and binding on the parties and enforceable under federal law, notwithstanding any contrary future decisions or orders of the CPUC.


	Fees and Expenses

The settlement agreement requires us to reimburse the CPUC for its professional fees and expenses incurred in connection with the Chapter 11 proceeding. These amounts will be recovered from customers over a reasonable time of up to four years. This accrual will be recorded when the applicable GAAP requirements are met. Corp’s professional fees and expenses incurred in connection with the Chapter 11 proceeding will not be reimbursed by us or from our customers.


	Refinancing Supported by a Dedicated Rate Component



	•	authorizing California legislation satisfactory to the CPUC, TURN and us is passed and signed into law allowing securitization of the regulatory asset and associated federal and state income and franchise taxes and providing for the collection in our rates of any portion of the associated tax amounts not securitized;



	•	the CPUC determines that, on a net present value basis, the refinancing would save customers money over the term of the securitized debt compared to the regulatory asset;



	•	the refinancing will not adversely affect our issuer or debt credit ratings; and



	•	we obtain, or decide we do not need, a private letter ruling from the Internal Revenue Service, or IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

We would be permitted to complete the refinancing in up to two tranches up to one year apart. The first tranche would be no less than the fully unamortized, after-tax balance of the regulatory asset. The second tranche would cover the associated federal and state income taxes and franchise taxes. However, we would not be required to securitize more than $3.0 billion in total in both tranches and, to the extent this would require callable debt or debt with earlier maturities than we would otherwise issue as part of the implementation of our plan of reorganization, these costs generally would be recoverable in rates. Upon refinancing, the rate of return on this regulatory asset would be eliminated. Instead, we would collect from customers amounts sufficient to service the securitized debt. We would use the securitization proceeds to rebalance our capital structure in order to maintain the capital structure provided in the settlement agreement.

Terms of Our Plan of Reorganization

The terms of the settlement agreement are reflected in our plan of reorganization, and the full settlement agreement is incorporated by reference into our plan of reorganization as a material and integral part of the plan. Our plan of reorganization was confirmed by the bankruptcy court on December 22, 2003. Our plan of

reorganization generally provides for payment in full of all allowed creditor claims (except for the claims of holders of pollution control bond-related obligations that will be reinstated) plus applicable interest on claims in certain classes and all cumulative dividends in arrears and mandatory sinking fund payments associated with our preferred stock. We will make these payments from the proceeds from the offering of a significant portion of the senior bonds, cash on hand and draws on credit and accounts receivable facilities. We also will establish one or more escrow accounts for disputed claims and deposit cash into these accounts.

Under our plan of reorganization, timely asserted environmental, fire suppression, pending litigation and tort claims and workers’ compensation claims will pass through the Chapter 11 proceeding unimpaired and will be satisfied by us in the ordinary course of business. However, all other valid undisputed claims against us as of the date the confirmation order was entered in the bankruptcy court will be satisfied, discharged and released in full on the effective date of our plan of reorganization. Subject to the provisions of the Bankruptcy Code, and in exchange for payments under our plan of reorganization, all persons and governmental entities are enjoined from asserting against us and our successors, or our or their assets or properties, any other or further claims or equity interests based upon any act or omission, transaction or other activity of any kind or nature that occurred before the confirmation date.

The two CPUC commissioners who did not vote to approve the settlement agreement and a municipality have filed appeals of the bankruptcy court’s confirmation order in the district court citing similar objections to those included in their requests for rehearing and reconsideration of the CPUC’s decision approving the settlement agreement. On January 5, 2004, the bankruptcy court denied a request to stay the implementation of our plan of reorganization until the appeals are resolved. The district court will set a schedule for briefing and argument of the appeals at a later date. No additional parties may request rehearings or make appeals of the bankruptcy court’s confirmation order. We cannot predict the timing or outcome of the requests for rehearing and appeals.

Conditions to the Effectiveness of Our Plan of Reorganization

Our plan of reorganization provides that it will not become effective unless and until each of the following conditions is satisfied or waived:


	•	the effective date occurs on or before March 31, 2004;

	•	all actions, documents and agreements necessary to implement our plan of reorganization are effected or executed;

	•	we and Corp have received all authorizations, consents, regulatory approvals, rulings, letters, no-action letters, opinions or documents that we and Corp determine are necessary to implement our plan of reorganization;

	•	our plan of reorganization has not been modified in a material way since the date of confirmation;


	•	we have consummated the sale of the senior bonds provided for under our plan of reorganization;



	•	Moody’s has issued an issuer rating for us of not less than Baa3 and S&P has issued long-term issuer credit ratings for us of not less than BBB-;



	•	Moody’s and S&P have issued credit ratings for the senior bonds provided for under our plan of reorganization of not less than Baa3 and BBB-, respectively;



	•	the CPUC has given final approval of the settlement agreement;



	•	we, Corp and the CPUC have executed and delivered the settlement agreement;



	•	the CPUC has given final approval of all of the financings, securities and accounts receivable programs provided for in our plan of reorganization; and



	•	the CPUC has given final approval of all rates, tariffs and agreements necessary to implement our plan of reorganization.

As described above, our plan of reorganization provides that it will not become effective unless and until the CPUC has given final approval of the settlement agreement, the financings, securities and accounts receivable programs provided for in our plan of reorganization, and all rates, tariffs and agreements necessary to implement our plan of reorganization. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed to by us and Corp to constitute final approval. Thus, the terms of our plan of reorganization would permit us and Corp to cause our plan of reorganization to become effective (and permit us to issue the senior bonds) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. In addition, our plan of reorganization provides that we may waive any or all of the conditions described under the first five bullets listed above with the consent of the Official Committee of Unsecured Creditors.

BUSINESS

Our Company

We are a leading vertically integrated electricity and natural gas utility. We operate in northern and central California and are engaged in the businesses of electricity generation, electricity transmission, natural gas transportation and storage, and electricity and natural gas distribution.

We have more customers than any other investor-owned utility in the United States. At December 31, 2003, we served approximately 4.9 million electricity distribution customers and approximately 3.9 million natural gas distribution customers in a service territory covering over 70,000 square miles. In 2003, we delivered approximately 80,156 GWh of electricity, which included approximately 8,978 GWh transmitted to direct access customers, and delivered approximately 804 Bcf of natural gas, which included approximately 525 Bcf of natural gas we did not purchase but which we transported on behalf of our customers.

We own, operate and control an extensive hydroelectric system in northern and central California and the Diablo Canyon nuclear power plant located near San Luis Obispo, California. At December 31, 2003, our electricity generation portfolio consisted of approximately 6,420 MW of owned generating capacity and approximately 5,450 MW of generating capacity under contract, for a combined generating capacity of approximately 11,870 MW. We are the largest non-governmental producer of hydroelectric power in the United States.

We own and operate an electricity transmission system that comprises most of the high-voltage electricity transmission lines and facilities in northern and central California. Our high-voltage transmission system consists of approximately 18,612 circuit miles of interconnected electricity transmission lines and support facilities.

We also own and operate a natural gas pipeline and storage system that is interconnected to all the major natural gas supply basins in western North America. This system consists of approximately 6,350 miles of transportation pipelines that extend from the California-Oregon border to the California-Arizona border. The backbone transportation system consists of a northern pipeline system with a delivery capacity of approximately 2.0 Bcf per day and a southern pipeline system with a delivery capacity of approximately 1.1 Bcf per day.

Our Business Strengths

As a leading vertically integrated electricity and natural gas utility, we have the following business strengths:

Substantial Asset Base. At December 31, 2003, our total assets were approximately $29.1 billion, of which approximately $18.1 billion was net property, plant and equipment. We expect that our asset base will grow with future capital expenditures. As a regulated utility, our operating performance is tied to the size of our asset base. We believe that our substantial asset base will provide us with a stable source of revenue in the future.

Extensive and Highly Attractive Service Territory. We provide electricity and/or natural gas distribution services in 48 of California’s 58 counties, which include most of northern and central California. We provide electricity and/or natural gas to approximately one out of every 20 people in the United States. Our service territory has a large and diversified economy with a gross domestic product of approximately $561 billion in 2002, equivalent to the twelfth largest economy in the world.

Essential Service Provider. We perform an essential public service as the principal provider of electricity and natural gas distribution services, electricity transmission services and natural gas transportation services in our service territory. In addition, for almost all our residential customers and most of our commercial and industrial customers, there are few commercially feasible alternative service providers.

Experienced Management Team and Employees. Our management and employees have substantial experience in the electricity and natural gas industries. We believe our management team’s and employees’ years of experience and expertise in managing our infrastructure contribute significantly to our success.

Electricity Utility Operations

Electricity Distribution Operations

Our electricity distribution network extends throughout all or a part of 46 of California’s 58 counties, comprising most of northern and central California. Our network consists of approximately 120,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). Our network includes 89 transmission substations and 45 transmission switching stations, 609 distribution substations and 117 low voltage distribution substations, and 264 combined transmission and distribution substations. A transmission substation is a facility where voltage is transformed from one transmission voltage level to another. Combined transmission and distribution substations have both transmission and distribution transformers.

Our distribution network interconnects to our electricity transmission system at 1,012 points. This interconnection between our distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to our customers. The distribution substations serve as the central hubs of our electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, we sell electricity from our distribution lines or facilities to entities, such as municipal and other utilities, that then resell the electricity.

The following chart shows the percentage of our total 2003 electricity deliveries represented by each of our major customer classes:

2003 ELECTRICITY DELIVERIES

(80,156 GWhs)

ELECTRICITY DELIVERED GRAPHIC


	Electricity Distribution Operating Statistics

The following table shows certain of our operating statistics from 1999 to 2003 for electricity sold or delivered, including the classification of sales and revenues by type of service.


				2003			2002			2001			2000			1999

Customers (average for the year):
	Residential				4,286,085			4,171,365			4,165,073			4,071,794			4,017,428
	Commercial				493,638			483,946			484,430			471,080			474,710
	Industrial				1,372			1,249			1,368			1,300			1,151
	Agricultural				81,378			78,738			81,375			78,439			85,131
	Public street and highway lighting				26,650			24,119			23,913			23,339			20,806
	Other electric utilities				4			5			5			8			12

			Total		4,889,127			4,759,422			4,756,164			4,645,960			4,599,238

Deliveries (in GWh):(1)
	Residential				29,024			27,435			26,840			28,753			27,739
	Commercial				31,889			31,328			30,780			31,761			30,426
	Industrial				14,653			14,729			16,001			16,899			16,722
	Agricultural				3,909			4,000			4,093			3,818			3,739
	Public street and highway lighting				605			674			418			426			437
	Other electric utilities				76			64			241			266			167

			Subtotal		80,156			78,230			78,373			81,923			79,230
	DWR				(23,342	)		(21,031	)		(28,640	)		—			—

			Total non-DWR electricity		56,814			57,199			49,733			81,923			79,230

Revenues (in millions):
	Residential			$	3,671		$	3,646		$	3,396		$	3,062		$	2,975
	Commercial				4,440			4,588			4,105			3,110			2,980
	Industrial				1,410			1,449			1,554			1,053			1,044
	Agricultural				522			520			525			420			404
	Public street and highway lighting				69			73			60			43			49
	Other electric utilities				24			10			39			26			17

			Subtotal		10,136			10,286			9,679			7,714			7,469
	DWR				(2,243	)		(2,056	)		(2,173	)		—			—
		Direct access credits			(277	)		(285	)		(461	)		(1,055	)		(348	)
	Miscellaneous(2)				(52	)		193			244			202			162
	Regulatory balancing accounts				18			40			37			(7	)		(51	)

			Total electricity operating revenues	$	7,582		$	8,178		$	7,326		$	6,854		$	7,232

Other Data:
	Average annual residential usage (kWh)				6,772			6,577			6,444			7,062			6,905
	Average billed revenues (cents per kWh):
		Residential			12.65			13.29			12.65			10.65			10.72
		Commercial			13.92			14.65			13.34			9.79			9.79
		Industrial			9.62			9.84			9.71			6.23			6.24
		Agricultural			13.35			13.00			12.83			11.00			10.81
	Net plant investment per customer			$	2,689		$	2,105		$	2,018		$	1,969		$	2,388



(1)	These amounts include electricity provided to direct access customers who procure their own supplies of electricity. Direct access deliveries amounted to 8,978 GWh in 2003, 7,433 GWh in 2002, 3,982 GWh in 2001, 9,662 GWh in 2000 and 9,022 GWh in 1999.



(2)	Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.


	*Electricity Resources*

The following chart shows the percentage of our total sources of electricity for 2003 represented by each major electricity resource:

2003 ELECTRICITY RESOURCES

(PIE CHART)

We are required to dispatch all of the electricity resources within our portfolio, including electricity provided under DWR contracts, in the most cost-effective way. To the extent our electricity resources are not sufficient to meet the demand of our customers, we purchase electricity from the wholesale electricity market. At other times, least-cost dispatch requires us to schedule more electricity than is necessary to meet our retail load and to sell this additional electricity on the wholesale electricity market. We typically schedule this excess electricity when the expected electricity sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract.


	Generation Facilities

At December 31, 2003, we owned and operated the following generation facilities, all located in California, listed by energy source:


Generation Type			County Location		Number of Units		Net Operating Capacity (MW)

Nuclear:
	Diablo Canyon			San Luis Obispo		2		2,174
Hydroelectric:
	Conventional			16 counties in northern
				and central California		107		2,684
	Helms pumped storage			Fresno		3		1,212

		Hydroelectric subtotal				110		3,896
Fossil fuel:
	Humboldt Bay(1)			Humboldt		2		105
	Hunters Point(2)			San Francisco		2		215
Mobile turbines				Humboldt		2		30

		Fossil fuel subtotal				6		350
Total						118		6,420



(1)	The Humboldt Bay facilities consist of a retired nuclear generation unit, or Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.



(2)	In July 1998, we reached an agreement with the City and County of San Francisco regarding our Hunters Point fossil fuel-fired plant, which has been designated as a “must run” facility by the ISO, to support system reliability. The agreement expresses our intention to retire the plant when it is no longer needed.

Diablo Canyon Power Plant. Our Diablo Canyon power plant consists of two nuclear power reactor units, each capable of generating up to approximately 1,087 MW of electricity. Unit 1 began commercial operation in May 1985 and the operating license for this unit expires in September 2021. Unit 2 began commercial operation in March 1986 and the operating license for this unit expires in April 2025. For the ten-year period ended December 31, 2003, our Diablo Canyon power plant achieved a capacity factor of approximately 88.5%.

The following table outlines the Diablo Canyon power plant’s refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 19 to 21 months. The average length of a refueling outage over the last five years has been approximately 35 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the steam generator replacements in 2008 and 2009 discussed below. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of up to 80 days to accommodate non-routine tasks, such as expanded steam generator inspection and repair, low pressure turbine rotor replacement and the first of two proposed steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

2004

2005

2006

2007

2008

Unit 1

Refueling

March

October

—

April

—

Duration (days)

—

Startup

May

November

June

Unit 2

Refueling

October

April

February

Duration (days)

—

Startup

December

—

May

—

April

During a routine inspection conducted as part of the last refueling of Unit 2 in February 2003, we found indications of steam generator tube cracking in locations and of a size not previously expected. After careful inspection and analysis, Unit 2 was able to safely restart after that outage and we received the approval of the NRC to operate without further steam generator inspection until the next scheduled refueling in the fall of 2004. We are, however, planning to accelerate the replacement of the steam generators in Unit 2 from 2009 to 2008. We plan to replace Unit 1’s steam generators in 2009. The capital expenditures necessary to complete these projects are discussed further in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Nuclear Fuel Agreements

Hydroelectric Generation Facilities. Our hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe and 5 miles of natural waterways. The system also includes water rights as specified in 83 permits and licenses and 163 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses, all of our powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last three years, we have received six renewed hydroelectric project licenses from the FERC. We currently have seven hydroelectric projects undergoing FERC relicensing. We will begin relicensing proceedings on two additional hydroelectric projects within the next two years. Licenses associated with 928 MW expire within the next five years. Licenses associated with approximately 2,959 MW expire between 2009 and 2043.

DWR Power Purchases

In January 2001, because of the deteriorating credit conditions of the California investor-owned electric utilities, the State of California authorized the DWR to purchase electricity to meet the utilities’ net open positions. California Assembly Bill 1X, or AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. We and the other California investor-owned electric utilities act as the billing and collection agent for the DWR’s sales of electricity to retail customers.

On September 19, 2002, the CPUC issued a decision allocating electricity from 19 of the DWR’s contracts to our customers. Electricity from DWR allocated contracts represented approximately 29% of our total sources of electricity in 2003. In January 2003, we became responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. During 2004, a total average capacity of approximately 2,700 MW of the electricity under the DWR allocated contracts is subject to “must take” provisions that require the DWR to take and pay for the electricity regardless of whether the electricity is needed. A total average capacity for 2004 of approximately 1,200 MW of the electricity under DWR allocated contracts is subject to provisions that require the DWR to pay a capacity charge, but do not require the purchase of electricity unless that electricity is dispatched and delivered.

The DWR is currently legally and financially responsible for these contracts. The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to us without the consent of the CPUC. The settlement agreement provides that the CPUC

will not require us to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:



	•	after assumption, our issuer rating by Moody’s will be no less than A2 and our long-term issuer credit rating by S&P will be no less than A;



	•	the CPUC first makes a finding that, for purposes of assignment or assumption, the DWR power purchase contracts to be assumed are just and reasonable; and



	•	the CPUC has acted to ensure that we will receive full and timely recovery in our retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

The settlement agreement does not limit the CPUC’s discretion to review the prudence of our administration and dispatch of the assumed DWR power purchase contracts consistent with applicable law.

Third Party Agreements

Qualifying Facilities. We are required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. Under PURPA, the CPUC required California investor-owned electric utilities to enter into a series of long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, price options and eligibility requirements. These agreements require us to pay for energy and capacity. Energy payments are based on the qualifying facility’s actual electricity output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement.

At December 31, 2003, we had qualifying facility power purchase agreements with approximately 300 qualifying facilities for approximately 4,400 MW in operation. Agreements for approximately 4,000 MW expire between 2004 and 2028. Qualifying facility power purchase agreements for approximately 400 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. We also have agreements with 50 qualifying facilities that are not currently providing or expected to provide electricity. The total of approximately 4,400 MW consists of approximately 2,600 MW from cogeneration projects, 800 MW from wind projects and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar and hydroelectric. On January 22, 2004, the CPUC adopted a decision that requires California investor-owned electric utilities to allow owners of qualifying facilities with power purchase agreements expiring before the end of 2005 to extend these contracts for five years. Qualifying facility power purchase agreements accounted for approximately 20% of our 2003 electricity sources, approximately 25% of our 2002 electricity sources and approximately 21% of our 2001 electricity sources. No single qualifying facility power purchase agreement accounted for more than 5% of our electricity sources during any of these periods.

As a result of the energy crisis, we owed approximately $1 billion to qualifying facilities when we filed our Chapter 11 petition. Through December 31, 2003, the principal payments made to the qualifying facilities amounted to $998 million.

Irrigation Districts and Water Agencies. We have contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, we must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements whether or not any hydroelectric power is supplied, and variable payments for operating and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. Our irrigation district and water agency contracts accounted for approximately 5% of our 2003 electricity sources, approximately 4% of our 2002 electricity sources and approximately 3% of our 2001 electricity sources.

Electricity Purchases to Satisfy the Residual Net Open Position. On January 1, 2003, we resumed purchasing electricity to meet our residual net open position. During that year, more than 14,000 GWh of electricity were bought and sold in the wholesale market to manage the 2003 residual net open position. Most of our contracts

entered into in 2003 had terms of less than one year. During 2004, we plan to enter into contracts of longer duration to satisfy our near-term residual net open position.

Renewable Energy Requirement. California law requires that, beginning in 2003, each California investor-owned electric utility must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. We met our 2003 commitment and the CPUC has approved several contracts intended to meet our 2004 renewable energy requirement.

WAPA

In 1967, we and WAPA entered into several long-term power contracts governing the interconnection of our respective electricity transmission systems, the use of our electricity transmission and distribution systems by WAPA, and the integration of our respective customer demands and electricity resources. These contracts give us access to WAPA’s excess hydroelectric power and obligate us to provide WAPA with electricity when its resources are not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004. Termination is subject to FERC approval, which we expect to receive.

The costs to fulfill our obligations to WAPA cannot be accurately estimated at this time. Both the purchase price and the amount of electricity WAPA will need from us in 2004 are uncertain. However, we expect that the cost of meeting our contractual obligations to WAPA will be greater than the amount that we receive from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, WAPA’s net amount purchased from us was approximately 4,804 GWh in 2003, 3,619 GWh in 2002 and 4,823 GWh in 2001.

Electricity Transmission

At December 31, 2003, we owned 18,612 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 42,798 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 120,428 circuit miles of distribution lines and substations with a capacity of 24,218 MVA. In 2003, we delivered 80,156 GWh to our customers, including 8,978 GWh delivered to direct access customers. We are interconnected with electric power systems in the Western Electricity Coordinating Council which includes 14 western states, Alberta and British Columbia, Canada and parts of Mexico.

In connection with electricity industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and rates for transmission service are set by the FERC. The ISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The ISO also is responsible for maintaining the reliability of the transmission system.

We have been working closely with the ISO to continue expanding the capacity on our electricity transmission system. We are engaged in the following significant expansion projects:

Path 15. WAPA and an independent transmission company, Trans-Elect NTD, Inc., are constructing a new 500 kV line to expand one segment of the transmission system, known as Path 15, which is located in the southern portion of our service area, and serves as part of the primary transmission path between northern California and southern California. The improvements are intended to mitigate transmission constraints in this area. We will interconnect the new 500 kV line at our existing substations at the line terminals and reconfigure our 230 kV and 115 kV facilities in the area to support a higher transfer capability through this section of the grid. This new 500 kV line is expected to be operational in October 2004.

Jefferson-Martin. This project entails laying 28 miles of 230 kV underground transmission facilities from Redwood City to Daly City that will provide additional transmission system reliability in San Francisco and northern San Mateo County. This project is expected to be completed in December 2005.


	*Nuclear Insurance*

We have several types of nuclear insurance for our Diablo Canyon power plant and Humboldt Bay Unit 3. We have insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per nuclear incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, we may be required to pay additional annual premiums of up to $36.7 million.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.9 billion. As required by the Price-Anderson Act, we purchased the maximum available public liability insurance of $300 million for the Diablo Canyon power plant. The balance of the $10.9 billion of liability protection is covered by a loss-sharing program, or secondary financial protection among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of reactors 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then we may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until we have fully paid our share of the liability. Since the Diablo Canyon power plant has two nuclear reactors over 100 MW, we may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $20 million per incident. Although the Price-Anderson Act expired on December 31, 2003, coverage continues to be provided to all licensees, including the Diablo Canyon power plant, that had coverage before December 31, 2003. Congress may address the renewal of the Price Anderson Act in future energy legislation.

In addition, we have $53.3 million of liability insurance for Humboldt Bay Unit 3 and have a $500 million indemnification from the NRC for public liability arising from nuclear incidents at Humboldt Bay Unit 3 covering liabilities in excess of the $53.3 million of liability insurance.

Natural Gas Utility Operations

We own and operate an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 38 of California’s 58 counties and includes most of northern and central California. In 2003, we served approximately 3.9 million natural gas distribution customers. The total volume of natural gas throughput during 2003 was approximately 804 Bcf.

At December 31, 2003, our natural gas system consisted of 39,510 miles of distribution pipelines, 6,350 miles of transportation pipelines and three storage facilities. Our distribution network connects to our transportation and storage system at approximately 2,200 major interconnection points. Our Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation, a subsidiary of National Energy & Gas Transmission, Inc., at the California-Oregon border. This line has a receipt capacity at the border of 2.0 Bcf per day. Our Line 300, which interconnects with the U.S. southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., or Transwestern, El Paso, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. Through interconnections with other interstate pipelines, we can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada and the southwestern United States. We are also supplied by natural gas fields in California.

We also own and operate three underground natural gas storage fields located along our transportation and storage system in close proximity to approximately 90% of our end-user demand. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to our northern California transportation system.

Since 1991, the CPUC has divided our natural gas customers into two categories — core and noncore customers. This classification is based largely on a customer’s annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercial natural gas customers. In 2003, core customers represented over 99% of our total customers and approximately 35% of our total natural gas deliveries, while noncore customers comprised less than 1% of our total customers and approximately 65% of our total natural gas deliveries.

We provide natural gas delivery services to all core and noncore customers connected to our system in our service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have us provide both delivery service and natural gas supply. When we provide both supply and delivery, we refer to the service as natural gas bundled service. Currently, over 99% of core customers, representing over 98% of core market demand, receive natural gas bundled services from us.

In March 2001 we stopped providing procurement service to noncore customers. During the winter of 2000-2001 when there was a steep increase in natural gas prices, many noncore customers switched to core service in order to receive procurement service from us. In December 2003, the CPUC approved our request to prohibit electricity generation, cogeneration, enhanced oil recovery and refinery, and other large noncore customers from electing to transfer to core service. The CPUC also required smaller noncore customers to sign up for a minimum five-year term if they elect to transfer to core service. We made this request because of our concern that significant transfers of noncore customers to core service would cause large increases in our natural gas supply portfolio demand and would raise prices for all other core procurement customers and obligate us to reinforce our pipeline system to provide core service reliability on a short-term basis to serve this new load.

We offer transportation, distribution and storage services as separate and distinct services to our noncore customers. These customers may elect to receive storage services from us or competitive storage providers. Noncore customers interconnected at a transportation level only pay for transportation service, while those interconnected at a distribution level pay for both transportation and distribution service. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to our transportation system is available for all natural gas marketers and shippers, as well as noncore customers.

Customers pay a distribution rate that reflects our costs to serve each customer class. We have regulatory balancing accounts for core customers designed to ensure that our results of operations over the long term are not affected by their consumption levels. Our results of operations can, however, be affected by noncore consumption levels because there are no similar regulatory balancing accounts related to noncore customers. Approximately 96% of our natural gas distribution base revenues are recovered from core customers and 4% are recovered from noncore customers.

The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and natural gas utilities. The 2002 California Gas Report updated our annual natural gas requirements forecast for the years 2002 through 2023, forecasting average annual growth in our natural gas deliveries of approximately 1.8%. The natural gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, and the number and location of electricity generation facilities.

The following chart shows the percentage of our total 2003 natural gas deliveries represented by each of our major customer classes:

2003 NATURAL GAS DELIVERIES

(804 Bcf)

ELECTRICITY DELIVERED GRAPHIC

Note: Deliveries to industrial and other natural gas utilities, which amounted to less than 1% of total deliveries in 2003, are not included in the chart.


	*Natural Gas Operating Statistics*

The following table shows our operating statistics from 1999 through 2003 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:


				2003			2002			2001			2000			1999

Customers (average for the year):
	Residential				3,744,011			3,738,524			3,705,141			3,642,266			3,593,355
	Commercial				208,857			206,953			205,681			203,355			203,342
	Industrial				1,988			1,819			1,764			1,719			1,625
	Other gas utilities				6			5			6			6			4

			Total		3,954,862			3,947,301			3,912,592			3,847,346			3,798,326

Gas supply (MMcf):
	Purchased from suppliers in:
		Canada			196,278			210,716			209,630			216,684			230,808
		California			(7,421	)(1)		19,533			20,352			32,167			18,956
		Other states			102,941			67,878			76,589			75,834			107,226

			Total purchased		291,798			298,127			306,571			324,685			356,990
	Net (to storage) from storage				1,359			(218	)		(27,027	)		19,420			(980	)
			Total		293,157			297,909			279,544			344,105			356,010
	Utility use, losses, etc. (2)				(14,307	)		(16,393	)		(8,988	)		(62,960	)		(47,152	)

			Net gas for sales		278,850			281,516			270,556			281,145			308,858

Bundled gas sales (MMcf):
	Residential				198,580			202,141			197,184			210,515			233,482
	Commercial				79,891			78,812			72,528			66,443			70,093


				2003			2002		2001			2000		1999

	Industrial				379			563		831			4,146		5,255
	Other gas utilities				—			—		13			41		28

			Total		278,850			281,516		270,556			281,145		308,858

Transportation only (MMcf):					525,353			508,090		646,079			606,152		484,218
Revenues (in millions):
	Bundled gas sales:
		Residential		$	1,836		$	1,379	$	2,308		$	1,681	$	1,543
		Commercial			697			499		783			513		449
		Industrial			1			3		16			35		24
	Miscellaneous				(30	)		128		(93	)		84		(47	)
	Regulatory balancing accounts				68			11		(253	)		132		(260	)

			Bundled gas revenues		2,572			2,020		2,761			2,445		1,709
	Transportation service only revenue				284			316		375			338		287

			Operating revenues	$	2,856		$	2,336	$	3,136		$	2,783	$	1,996

Selected Statistics:
Average annual residential usage (Mcf)					53			54		53			59		65
Average billed bundled gas sales revenues per Mcf:
		Residential		$	9.25		$	6.82	$	11.70		$	7.98	$	6.61
		Commercial			8.73			6.33		10.80			7.72		6.40
		Industrial			2.48			4.35		19.15			8.53		4.69
Average billed transportation only revenue per Mcf					0.54			0.62		0.58			0.56		0.59
	Net plant investment per customer			$	1,261		$	1,006	$	970		$	1,003	$	1,011



(1)	This total includes sales of 21,632 MMcf made principally at the California border. Purchases in California totaled 14,211 MMcf.



(2)	Includes fuel for our fossil fuel-fired generation plants.


	*Natural Gas Supplies*

We purchase natural gas to serve our core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of our portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2003, we purchased approximately 292,000 MMcf of natural gas (net of the sale of excess supply) from 48 suppliers. Substantially all this natural gas was purchased under contracts with a term of less than one year. Our largest individual supplier represented approximately 9.6% of the total natural gas volume we purchased during 2003.

The following table shows the total volume and the average price of natural gas in dollars per Mcf of our natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess

supplies of gas. In 2003, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.



	2003					2002				2001				2000				1999

				Avg.				Avg.				Avg.				Avg.				Avg.
	MMcf			Price		MMcf		Price		MMcf		Price		MMcf		Price		MMcf		Price

Canada		196,278		$	4.73		210,716	$	2.42		209,630	$	4.43		216,684	$	4.05		230,808	$	2.50
California (1)		(7,421	)	$	3.39		19,533	$	2.88		20,352	$	11.55		32,167	$	8.20		18,956	$	2.45
Other states (substantially all U.S. southwest)		102,941		$	4.63		67,878	$	3.04		76,589	$	10.41		75,834	$	5.99		107,226	$	2.42
Total/weighted average		291,798		$	4.73		298,127	$	2.59		306,571	$	6.40		324,685	$	4.92		356,990	$	2.47


(1)	This total includes sales made principally at the California border of 21,632 MMcf. Purchases in California totaled 14,211 MMcf.

We also routinely sell contracted natural gas supplies that exceed daily core customer requirements and to comply with pipeline balancing requirements. We also may sell natural gas supplies if we can repurchase those natural gas supplies at a lower cost, thereby lowering overall costs for core natural gas customers. These sales opportunities increase during periods of price volatility. During 2003, both daily core customer requirements and natural gas prices were extremely volatile, leading to a high quantity of natural gas sales. Total natural gas sales in 2003 were approximately 7% of the total volume of natural gas supplies purchased for our core natural gas customers.


	*Natural Gas Gathering Facilities*

Our natural gas gathering system collects and processes natural gas from third-party wells in California. The natural gas is processed to remove various impurities from the natural gas stream and to odorize the natural gas so that it may be detected in the event of a leak. The facilities include 475 miles of gas gathering pipelines, as well as dehydration, separation, regulation, odorization and metering equipment located at 62 stations. The gas gathering system is geographically dispersed and is located in 14 California counties. Approximately 120 MMcf per day of natural gas flows through our gas gathering system.


	*Interstate and Canadian Natural Gas Transportation Services Agreements*

In 2003, approximately 67% of our natural gas supplies came from western Canada. We have a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers’ service demands. We have firm transportation agreements for delivery of natural gas from western Canada to the United States-Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System. These companies’ pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with our natural gas transportation system in the area of California near Malin, Oregon. We have a firm transportation agreement with Gas Transmission Northwest Corporation for these services.

During 2003, approximately 29% of our natural gas supplies came from the western United States, excluding California. We have firm transportation agreements with Transwestern and El Paso to transport this natural gas from supply points in this region to interconnection points with our natural gas transportation system in the area of California near Topock, Arizona.

The following table shows certain information about our firm natural gas transportation agreements, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require us to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System, and the FERC in all other cases. We recover these demand charges through the CPIM. We may, upon prior notice, extend each of these natural gas transportation agreements for additional minimum terms ranging, depending on the particular agreement, from one to ten years. On the

FERC-regulated pipelines, we have a right of first refusal allowing us to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, we would be required to match the competing bid with respect to both price and term.


	Expiration		Quantity		Demand Charges for the Year
Pipeline	Date		MDth per day		Ended December 31, 2003

					(in millions)
El Paso Natural Gas Company		10/31/2003		100	$	9.5
El Paso Natural Gas Company		12/31/2004		64		4.5
TransCanada NOVA Gas Transmission, Ltd.		12/31/2005		593		23.6
TransCanada PipeLines Ltd., B.C. System		10/31/2005		584		10.6
Gas Transmission Northwest Corporation		10/31/2005		610		55.0
Transwestern Pipeline Co.		03/31/2007		150		15.8
El Paso Natural Gas Company		03/31/2007		40		3.8
El Paso Natural Gas Company		04/30/2005		100		1.1

Competition

Historically, energy utilities operated as regulated monopolies within service territories where they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport and distribute energy. Services were priced on a combined, or bundled, basis with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertook a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices. In recent years, energy utilities have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies. The most significant of these services are the commodity components, the supply of electricity and natural gas.

The driving forces behind these competitive pressures have been customers who believe they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators responded to these forces by providing for more competition in the energy industry. Regulators and legislators, to varying degrees, have required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.


	*The Electricity Industry*

The FERC’s policies have supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities’ transmission grids. The FERC’s subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. The FERC’s standard market design proposal issued in July 2002 encourages unbundled transmission. The ISO also issued its own comprehensive market design proposal to effect changes to the structure and operation of the California electricity market, subject to the FERC’s approval. The FERC has approved the first phase of the ISO’s new rules and implementation of the first phase is expected to be completed in the second quarter of 2004. A later phase to establish integrated forward markets and locational marginal pricing and revise congestion management would be implemented in the future, if approved by FERC. The ISO is expected to file proposed tariff language with the FERC later in 2004 to address these issues. Both the timing and substance of the FERC’s regional transmission organization policy and the FERC’s and the ISO’s market design processes may be affected if an energy bill is passed by Congress.

In July 2003, in order to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generator and transmission infrastructure, the FERC issued final rules on the interconnection of generators larger than 20 MW with a transmission system. The rules will require regulated transmission providers, such as us or the ISO, generally to use standard interconnection procedures and a standard agreement for generator interconnections. These rules would require us and the ISO to revise the existing agreements and procedures used when constructing facilities to interconnect new generators. Numerous parties have requested rehearing and a stay of the generator interconnection rules. Although the FERC has not yet ruled on the requests for rehearing, the FERC has ordered that the rules will not become effective until after the FERC accepts new tariff changes to implement the rules. We, along with other transmission owners, filed proposed tariffs changes on January 20, 2004. It is uncertain when the FERC will act on the rehearing requests or the proposed tariff changes. Further the FERC’s rulemaking on generator interconnections may be affected if an energy bill is passed by Congress.

In 1998, California implemented AB 1890, which mandated the restructuring of the California electricity industry and established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity. AB 1890 also gave customers the choice of continuing to buy electricity from the California investor-owned electric utilities or, beginning in April 1998, entering into contracts to purchase electricity from alternate energy service providers (i.e., becoming direct access customers). The CPUC suspended the right of retail end-user customers to become direct access customers on September 20, 2001. The CPUC has assessed an additional charge on certain direct access customers to avoid a shift of costs from direct access customers to customers who receive bundled service.

In October 2003, the CPUC instituted a rulemaking implementing AB 117, which permits California cities and counties to purchase and sell electricity for their residents once they have registered as community choice aggregators. Under AB 117, we would continue to provide distribution, metering and billing services to the community choice aggregators’ customers and be those customers’ provider of electricity of last resort. However, once registration has occurred, each community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from us. To prevent a shifting of costs to customers of a utility who receive bundled services, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator will pay an appropriate share of the DWR’s and our costs. AB 117 also authorized us to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from ratepayers any costs of implementing the program not reasonably attributable to a community choice aggregator.

We face competition in the electricity distribution business as a result of the construction of duplicate distribution facilities to serve specific existing or new customers, condemnation of our distribution facilities by local governments or districts, self-generation by our customers and technological developments. These and other forms of competition may result in stranded investment capital, loss of customer growth and additional barriers to cost recovery. As customers and local public officials explore their energy options in light of the recent California energy crisis, these bypass risks are increasing and may increase further if our rates exceed the cost of other available alternatives.

A number of local governments and districts in California are considering whether to provide electricity distribution services within our service territory. The City and County of San Francisco (along with other California communities) have been considering municipalization of our electricity distribution system within their jurisdictions. In addition, the Sacramento Municipal Utility District currently is considering annexing portions of our service territory, with the objective of enabling the district to replace us within these areas. Some existing public power entities, such as the Modesto and Merced Irrigation Districts, also are expanding their services in our service area. Finally, some districts that are not currently distributing electricity, including the El Dorado Irrigation District and the South San Joaquin Irrigation District, are considering building facilities that would duplicate our facilities. In May 2003, the South San Joaquin Irrigation District revealed its plans to invest over $40 million to duplicate our distribution facilities and begin serving existing and new customers in and around Manteca. In 2002, the City of Hercules formed its own municipal utility for the purpose of competing

with us to serve new customers within the city. In 2003, the City of Hercules began providing electricity service to a 200-home subdivision and a large commercial customer, and has been actively pursuing additional residential and commercial customers. We cannot currently predict the impact of these actions on our business, although one possible outcome is a decline in the demand for the electricity that we provide, which would result in a decline in our revenues.


	*The Natural Gas Industry*

FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service regardless of whether the customer (often a local gas distribution company) buys the natural gas commodity from these companies.

In 1998, we implemented the gas accord under which the natural gas transportation and storage services we provide were separated for ratemaking purposes from our distribution services. The gas accord changed the terms of service and rate structure for natural gas transportation, allowing our core customers to purchase natural gas from competing suppliers. Our noncore customers purchase their natural gas from producers, marketers and brokers, and purchase their preferred mix of transportation, storage and distribution services from us. Although they can select the gas suppliers of their choice, substantially all core customers buy natural gas, as well as transportation and distribution services, from us as bundled service. The gas accord market structure has been extended by the CPUC through 2005.

We compete with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas and the quality and reliability of transportation services. The most important competitive factor affecting our market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in our case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that we charge for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, our market share of transportation services into southern California decreases. In addition, Kern River Pipeline Company completed a major expansion of its pipeline system in May 2003 that increased its capacity to deliver natural gas into the southern California market by approximately 900 MMcf per day. As a result this expansion, the volume of natural gas that we deliver to the southern California market may decrease, although to date we have not experienced any significant decrease in our volumes shipped. We also compete for storage services with other third-party storage providers, primarily in northern California.

From time to time, existing pipeline companies propose to expand their pipeline systems for delivery of natural gas into northern and central California. As a result of the California energy crisis, several new natural gas pipeline proposals were initiated to serve proposed new generation facilities in northern and central California. Many of the electricity generation projects have been cancelled or delayed, making it difficult for sponsors of the various gas pipeline projects to acquire enough firm capacity commitments to go forward with construction.

Employees

At December 31, 2003, we had approximately 20,300 employees. Of our employees, approximately 13,500 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or ESC; and the International Union of Security Officers/SEIU, Local 24/7, or SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2007. The SEIU collective bargaining agreement expires on February 28, 2008.

Our Properties

Our corporate headquarters consist of approximately 1.8 million square feet of office space located in several buildings in San Francisco, California. In addition to this corporate office space, we own or have obtained the right to occupy and/or use real property comprising our electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under “— Electricity Utility Operations” and “— Natural Gas Utility Operations.” In total, we occupy 9.3 million square feet, including approximately 975,000 square feet of leased office space. We occupy or use real property that we do not own primarily through various leases, easements, rights-of-way, permits or licenses from private landowners or governmental authorities. We currently own approximately 170,000 acres of land, approximately 140,000 acres of which we will encumber with conservation easements or donate to public agencies or non-profit conservation organizations under the settlement agreement with the CPUC. Approximately 44,000 acres of this land may be either donated or encumbered with conservation easements. The remaining land contains our or a joint licensee’s hydroelectric generation facilities and may only be encumbered with conservation easements.

Our Regulatory Environment

Various aspects of our business are subject to a complex set of energy, environmental and other governmental laws, regulations and regulatory proceedings at the federal, state and local levels. This section and the “Ratemaking Mechanisms” section below summarize some of the more significant energy laws, regulations and regulatory mechanisms affecting us. These sections are not an exhaustive description of all the energy laws, regulations and regulatory proceedings that affect us. The energy laws, regulations and regulatory proceedings may change or be implemented or applied in a way that we do not currently anticipate. For discussion of specific regulatory proceedings affecting us, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	*Federal Energy Regulation*


	The FERC

The FERC is an independent agency within the DOE, that regulates the transmission of electricity in interstate commerce and the sale for resale of electricity in interstate commerce. The FERC regulates electricity transmission, interconnections, tariffs and conditions of service of the ISO and the terms and rates of wholesale electricity sales. The ISO is responsible for providing open access transmission service on a non-discriminatory basis, meeting applicable reliability criteria, planning transmission system additions and assuring the maintenance of adequate reserves of generation capacity. In addition, the FERC has jurisdiction over our electricity transmission revenue requirements and rates, the licensing of substantially all of our hydroelectric generation facilities and the interstate sale and transportation of natural gas.

In response to the California energy crisis, the FERC issued a series of orders in the spring and summer of 2001 and July 2002 aimed at prospectively mitigating extreme wholesale energy prices like those that prevailed in 2000 and 2001. These orders established a cap on bids for real-time electricity and ancillary services of $250 per MWh (unless a generator could demonstrate that its costs justified a rate in excess of $250 per MWh) and established various automatic mitigation procedures. As of December 2003, all sellers with market-based rate authority became subject to, and incorporated in their market-based rate tariffs, behavioral conditions designed to prevent market manipulation.

In February 2004, the FERC is expected to consider ISO market monitoring and oversight in connection with the FERC’s review of the ISO’s standard market design proposals. Market monitoring and mitigation also may be affected if an energy bill is passed by Congress.


	The NRC

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including our Diablo Canyon power plant and Humboldt Bay Unit 3. NRC regulations require extensive

monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. Safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at our Diablo Canyon power plant and additional significant capital expenditures could be required in the future.


	*State Energy Regulation*


	The CPUC

The CPUC has jurisdiction to set the rates, terms and conditions of service for our electricity distribution, natural gas distribution and natural gas transportation and storage services in California. The CPUC also has jurisdiction over our issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of our electricity and natural gas retail customers, rate of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning and aspects of the siting of the electricity transmission system. Ratemaking for retail sales from our generation facilities is under the jurisdiction of the CPUC. To the extent this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.


	California Legislature

Over the last several years, our operations have been significantly affected by statutes passed by the California legislature, including:



	•	Assembly Bill 1890. AB 1890 mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and our customers were given the choice of becoming direct access customers.



	•	Assembly Bill 6X. AB 6X, enacted in January 2001 in response to the California energy crisis, prohibited disposition of utility-owned generation facilities before January 1, 2006.



	•	Assembly Bill 1X. AB 1X authorized the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities’ retail customers. AB 1X required the California investor-owned electric utilities, including us, to deliver that electricity and act as the DWR’s billing and collection agent.



	•	Senate Bill 1976. SB 1976, enacted in September 2002, required the CPUC to allocate electricity from contracts that the DWR entered into under AB 1X among the customers of the California investor-owned electric utilities, required the utilities to file short- and long-term procurement plans with the CPUC, contemplated that the utilities would resume buying electricity pursuant to these plans by January 1, 2003, and mandated new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under approved procurement plans.



	•	Senate Bill 1078. SB 1078, enacted in September 2002, created a renewable portfolio standard for investor-owned utilities that requires annual 1% increases of renewable electrical procurement purchases until renewable resources equal 20% of total retail sales in 2017.

In connection with the settlement agreement, we and Corp agreed to seek to refinance the remaining unamortized pre-tax balance of the $2.21 billion after-tax regulatory asset and associated federal, state and franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of our plan of reorganization using a securitized financing supported by a dedicated rate component that would require enactment of authorizing California legislation. On January 22, 2004, the CPUC approved proposed legislation, Senate Bill 772, that would authorize a dedicated rate component to securitize the regulatory asset and the associated taxes. The California Assembly’s Utilities and Commerce Committee approved the proposed

legislation on February 2, 2004. The proposed legislation will next be considered by the California Assembly’s Appropriations Committee. Any adopted legislation must be satisfactory to the CPUC, us and TURN, and the refinancing must not adversely affect our issuer or debt credit ratings among other conditions.


	The California Energy Resources Conservation and Development Commission

The California Energy Resources Conservation and Development Commission, commonly called the CEC, is the state’s lead energy policy agency. The CEC also is responsible for the siting of all thermal power plants over 49 MW and administers public interest research and development funds, as well as renewable resource programs, including the renewable energy portfolio standard program.


	*Other Regulation*

We obtain a number of permits, authorizations and licenses in connection with the construction and operation of our generation facilities, electricity transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. We currently have seven hydroelectric projects and one transmission line project undergoing FERC relicensing. We will begin relicensing proceedings on two additional hydroelectric projects within the next two years.

We have over 520 franchise agreements with various cities and counties that permit us to install, operate and maintain our electric, natural gas, oil and water facilities in public streets and roads. In exchange for the right to use public streets and roads, we pay annual fees to the cities and counties under the franchises. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. However, there are 38 charter cities that can set a fee of their own determination. We also periodically obtain permits, authorizations and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations and licenses we have rights to occupy and/or use public property for the operation of our business and to conduct certain related operations.

Ratemaking Mechanisms


	*Overview*


	Transition from Frozen Rates to Cost of Service Ratemaking

Frozen electricity rates, which began on January 1, 1998, were designed to allow us to recover our authorized utility costs, and to the extent frozen rates generated revenues in excess of these costs, to recover our transition costs. Although the surcharges implemented in 2001 effectively increased the actual rate to customers, under the frozen rate structure, increases in our authorized revenue requirements did not increase our revenues. In addition, DWR revenue requirements reduced our revenues under the frozen rate structure. As a result of a January 2004 CPUC decision determining that the rate freeze ended on January 18, 2001, combined with the revised electricity rates that will be implemented as a result of the CPUC’s approval of the rate design settlement, we expect that our rates will reflect cost of service ratemaking and rates will be calculated based on the aggregate of various authorized rate components. Changes in any individual revenue requirement will change customers’ electricity rate.

Revenue Requirements

Before the rates for our electricity and natural gas utility services can be set, revenue requirements must first be determined. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for

each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs. Revenue requirements are designed to allow a utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its rate base. Revenue requirements are then allocated among customer classes and specific rates designed to produce the required revenue are established. In our rate cases, intervenors have the opportunity to comment on our application. The issues raised by these comments are then resolved by the appropriate regulatory agency. If we and the intervenors can settle these issues, these settlements are submitted to the regulatory agency for approval.


	General Rate Cases

Our primary revenue requirement proceeding is the general rate case filed with the CPUC. In the GRC, the CPUC authorizes us to collect from customers an amount known as base revenues to recover base business and operational costs related to our electricity and natural gas distribution and electricity generation operations. The general rate case typically sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in general rate case proceedings based on a forecast of costs for the first, or test, year. After authorizing the revenue requirements, the CPUC allocates revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levels. Typical intervenors in our general rate case include the ORA and TURN.


	Attrition Rate Adjustments

The CPUC may authorize us to receive annual increases in the base revenues authorized for the test year of a general rate case for the years between general rate cases to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that we are authorized to collect in rates for electricity and natural gas distribution and electricity generation operations.


	Cost of Capital Proceedings

The CPUC generally conducts an annual cost of capital proceeding to determine our authorized capital structure and the authorized rate of return that we may earn on our electricity and natural gas distribution and electricity generation assets. The cost of capital proceeding establishes the percentage components that common equity, preferred equity and debt will represent in our total authorized capital structure for a specific year. The CPUC then establishes the authorized return on common equity, preferred equity and debt that we will have the opportunity to collect in our authorized rates. For 2005, this proceeding also will set the authorized rate of return for our gas transportation and storage assets.


	Baseline Allowance

The CPUC sets and periodically revises a baseline allowance for our residential gas and electricity customers. A customer’s baseline allowance is the amount of its monthly usage that is covered under the lowest possible natural gas or electricity rate. Electricity baseline usage is also exempt from certain surcharges. Natural gas or electricity usage in excess of the baseline allowance is covered by higher rates that increase with usage.


	*DWR Electricity and DWR Revenue Requirements*

As a consequence of the California energy crisis, on January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the DWR to purchase electricity to maintain the continuity of supply to retail customers. This was followed by AB 1X, which authorized the DWR to purchase electricity and sell that electricity directly to the California investor-owned electric utilities’ retail end-user customers and to issue revenue bonds to finance electricity purchases. AB 1X also required us to deliver the electricity purchased by the DWR over our distribution system and to act as a billing and collection agent for the DWR, without taking title to DWR purchased electricity or reselling it to our customers.

AB 1X allows the DWR to recover its costs of electricity and associated transmission and related services, principal and interest on bonds issued to finance the purchase of electricity, administrative costs and certain other

amounts associated with purchasing electricity through a revenue requirement. AB 1X also authorizes the CPUC to set rates to cover the DWR’s revenue requirements, but prohibits the CPUC from increasing electricity rates for residential customers who use less electricity than 130% of their existing baseline quantities.

Under AB 1X, the DWR was prohibited from entering into new electricity purchase contracts and from purchasing electricity on the spot market after December 31, 2002. SB 1976, which became law in September 2002, required the CPUC to allocate electricity from existing DWR contracts among the customers of the California investor-owned electric utilities, including our customers. On September 19, 2002, the CPUC issued a decision allocating electricity from the DWR contracts to the customers of the three California investor-owned electric utilities. The DWR continues to be legally and financially responsible for these contracts. The electricity provided under 19 of the DWR contracts was allocated to our customers. We are responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts.

The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power charge. The DWR pays for its costs associated with its $11.3 billion bond offering completed in November 2002 from another revenue requirement collected from electricity customers through what is known as a bond charge. The proceeds of this bond offering were used to repay the state of California and lenders to the DWR for electricity purchases made before the implementation of the DWR’s revenue requirement and to provide the DWR with funds to make its electricity purchases. Because we act as a billing and collection agent for the DWR, amounts collected for the DWR and any adjustments are not included in our revenues.


	*DWR Allocated Contracts*

The DWR provided approximately 30% of the electricity delivered to our customers in 2003. The DWR purchased the electricity under contracts with various generators and through open market purchases. We are responsible for administration and dispatch of the DWR’s electricity procurement contracts allocated to our customers, for purposes of meeting a portion of our net open position. The DWR remains legally and financially responsible for the electricity procurement contracts.

The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered.



	•	after assumption, our issuer rating by Moody’s will be no less than A2 and our long-term issuer credit rating by S&P will be no less than A;



	•	the CPUC first makes a finding that, for purposes of assignment or assumption, the DWR power purchase contracts to be assumed are just and reasonable; and



	•	the CPUC has acted to ensure that we will receive full and timely recovery in our retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.


	*Procurement Resumption and Procurement Plans*

On January 1, 2003, the California investor-owned electric utilities resumed responsibility for procuring electricity to meet their residual net open positions. They also became responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions

associated with those contracts. The utilities also were required by SB 1976 to submit short-term and long-term procurement plans to the CPUC for approval. In December 2003, the CPUC approved our short-term 2004 procurement plan. We have also received authority to enter into electricity purchase contracts of up to five years in duration to meet our residual net open position so long as we begin receiving electricity under these contracts during 2004. In the January 2004 CPUC decision discussed below, the CPUC also adopted short-term procurement authority for 2005 for the California investor-owned electric utilities in order to allow them to begin the normal cycle for procuring products required for summer 2005; however, contracts for 2005 cannot exceed one year.

Effective January 1, 2003, under California law we established the ERRA, a balancing account, designed to track and allow recovery of the difference between the recorded procurement revenues and actual costs incurred under our authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an investor-owned utility’s electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate, when the aggregate overcollections or undercollections exceed 5% of the utility’s prior year electricity procurement revenues, excluding amounts collected for the DWR. These mandatory adjustments will continue until January 1, 2006. The CPUC’s review of our procurement activities will examine our least-cost dispatch of our resource portfolio (including the DWR allocated contracts), fuel expenses for our electricity generation facilities, contract administration (including administration of the DWR allocated contracts) and our electricity procurement contracts. As a result of this review, some of our procurement costs could be disallowed.


	*Electricity Transmission*

Our electricity transmission revenues and our wholesale and retail transmission rates are subject to authorization by the FERC. We have two sources of transmission revenues, charges under our transmission owner tariff and charges under specific contracts with existing wholesale transmission customers that pre-date our participation in the ISO. Customers that receive transmission services under these pre-existing contracts, referred to as existing transmission contract customers, are charged individualized rates based on the terms of their contracts. Transmission rates established by the FERC are included by the CPUC in our retail electricity rates and collected from retail electricity customers receiving bundled service under the federal filed rate doctrine.


	FERC Transmission Owner Rate Cases

Under the FERC’s regulatory regime, we are able to file a new base transmission rate case under our transmission owner tariff whenever we deem it necessary to increase our rates within certain guidelines set forth by the FERC. We are typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.

Our transmission owner tariff includes two rate components:



	•	base transmission rates, which are intended to recover our operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity; and



	•	rates to recover ISO charges for both reliability service costs and an ISO charge associated with a ten-year shift from utility-specific transmission charges to an ISO grid-wide charge, both of which are discussed below.

We derive the majority of our transmission revenue from base transmission rates.


	Transmission Control Agreement

We are a party to a TCA with the ISO and other participating transmission owners. As a transmission owner, we are required to give two years notice and receive regulatory approval if we wish to withdraw from the TCA. Under this agreement, the transmission owners, which also include SCE, San Diego Gas & Electric Company and several municipal utilities, assign operational control of their electricity transmission systems to the ISO. In addition, as a party to the TCA, we are responsible for a share of the costs of RMR agreements between the ISO and owners of the RMR plants. We are also an owner of some of these RMR plants for which we receive

revenue from the ISO. Under the RMR agreements, RMR plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO’s demand.


	Reliability Services Costs

The ISO bills us for reliability services based on payments that the ISO makes to generators under RMR agreements and to others to support reliability of our transmission system. The costs of RMR agreements attributed to supporting our historic transmission control area are charged to us as a participating transmission owner. These costs were approximately $330 million in 2003. Under our transmission owner tariff, we charge our customers rates designed to recover these reliability service charges, without mark-up or service fees. We track costs and revenues related to reliability services in the reliability services balancing account. Periodically, our electricity transmission rates are adjusted to refund over-collections to our customers or to collect any under-collections from customers.


	Transmission Access Charge

In March 2000, the ISO filed an application with the FERC seeking to establish its own transmission access charge as directed by AB 1890. The ISO’s transmission access charge methodology provides for transition to a uniform statewide high-voltage transmission rate, based on the revenue requirements of all participating transmission owners associated with facilities operated at 200 kV and above. The transmission access charge methodology also requires us and other transmission owners, during a ten-year transition period, to pay a charge intended to reimburse other transmission owners who are generally new ISO participants, whose costs are higher than that embedded in the uniform rate. Under the ISO’s application, our obligation for this cost differential would be capped at $32 million per year during the ten-year transition period. A hearing in this matter was conducted at the FERC in October and November 2003 and an initial decision from the presiding administrative law judge is scheduled to be issued in March 2004.


	*Natural Gas*


	The Gas Accord

In 1998, we implemented the gas accord, under which our natural gas transportation and storage services were separated for ratemaking purposes from our distribution services. The gas accord established natural gas transportation rates and natural gas storage rates. On December 18, 2003, the CPUC approved our application to retain the gas accord market structure for 2004 and 2005 and resolved the rates, and terms and conditions of service for our natural gas transportation and storage system for 2004. We continue to be at risk of not recovering our natural gas transportation and storage costs and do not have regulatory balancing account protection for overcollections or undercollections of natural gas transportation or storage revenues.


	Biennial Cost Allocation Proceeding

Our natural gas distribution costs and balancing account balances are allocated to customers in the biennial cost allocation proceeding. This proceeding is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any undercollection, or refund to customers any overcollection, in the balancing accounts. Balancing accounts for natural gas and public purpose program revenue requirements accumulate differences between authorized revenue requirements and actual base revenues.


	Natural Gas Procurement

We set the natural gas procurement rate for core customers monthly based on the forecasted costs of natural gas, core pipeline capacity and storage costs. We reflect the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with undercollections and overcollections taken into account in subsequent monthly rates.

Under the CPIM, our natural gas purchase costs (including Canadian and interstate capacity and volumetric transportation charges) are compared to an aggregate market-based benchmark based on a weighted average of

published monthly and daily natural gas price indices at the points where we typically purchase natural gas. Costs that fall within a tolerance band, which is currently between 99% and 102% of the benchmark, are considered reasonable and fully recoverable, in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and our customers receive three-fourths of the savings when the costs are below 99% of the benchmark. Any awards associated with CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual period ending October 31 that is used to measure the CPIM. These awards are not included in earnings until approved by the CPUC.


	Interstate and Canadian Natural Gas Transportation and Storage

Our interstate and Canadian natural gas transportation agreements with third party service providers are governed by tariffs that detail rates, rules and terms of service for the provision of natural gas transportation services to us on interstate and Canadian pipelines. United States tariffs are approved by the FERC in a ratemaking review process and the Canadian tariffs are approved by the Alberta Energy and Utilities Board and the National Energy Board. Our agreements with interstate and Canadian natural gas transportation service providers are administered as part of our core natural gas procurement business. Natural gas is transported pursuant to these agreements from the points at which we take delivery of natural gas — typically in Canada and the southwestern United States — to the points at which our natural gas transportation system begins.

Capacity Purchases on El Paso and Transwestern Pipelines. In July 2002, the CPUC ordered certain California utilities to contract for additional amounts of El Paso pipeline capacity to gain firm access to the southwest natural gas producing basins. The CPUC believed that if the utilities had firm access rights, they would have been able to mitigate the gas price spikes that occurred during the energy crisis when shippers raised the price of gas at the California border. The CPUC pre-approved the costs of these contracts as just and reasonable. Since the July 2002 decision, we have signed contracts for capacity on the El Paso pipeline costing approximately $50.8 million for the period from November 2002 to December 2007. The July 2002 decision also ordered these California utilities to retain their then-current interstate pipeline capacity levels and sell any excess capacity to third parties under short-term capacity release arrangements. It also ordered that, to the extent the California utilities comply with the decision, they will be able to fully recover their costs associated with existing capacity contracts.

Under a previous CPUC decision, we could not recover in rates any costs paid to Transwestern for natural gas pipeline capacity through 1997. We pay approximately $22 million in annual reservation charges under the Transwestern contract. The gas accord provided for partial recovery of Transwestern costs after 1997. In January 2004, the CPUC approved a settlement with TURN that allows us to fully recover Transwestern costs retroactive to July 2003.

In December 2002, the CPUC granted our request to recover in rates El Paso pipeline capacity costs and prepayments made to El Paso from all natural gas customers. We began recovering these costs from all natural gas customers in March 2003. In January 2004, the CPUC re-allocated all the costs, including Transwestern costs incurred since July 2003, to our core customers, because the pipeline capacity is used to serve core customers. Our noncore customers and core aggregation customers will receive a refund or bill credit for El Paso capacity costs paid by these customers between March 2003 and January 2004.

Environmental Matters

The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance. The information below reflects current estimates that are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner’s responsibility and the availability of recoveries or contributions from third parties.


	*General*

We are subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of our personnel and the public. These laws and requirements relate to a broad range of activities, including:



	•	the discharge of pollutants into air, water and soil;



	•	the identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting of, remediation of and emergency response in connection with, hazardous, and radioactive substances; and



	•	land use, including endangered species and habitat protection.

The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. These laws and requirements also may require us, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, we may need to spend substantial amounts from time to time to construct, acquire, modify or replace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations and clean up or decommission waste disposal areas at our current or former facilities and at third-party sites where we may have disposed of wastes.

Generally, we have recovered the costs of complying with environmental laws and regulations in our rates, subject to reasonableness review. Environmental costs associated with sites that contain hazardous wastes are subject to a special ratemaking mechanism.

In 1994, the CPUC established a ratemaking mechanism under which we are authorized to recover hazardous waste remediation costs for environmental claims (e.g., for cleaning up our facilities and sites where we have sent hazardous substances) from customers. That mechanism allows us to include 90% of the hazardous waste remediation costs in our rates without review.

Ten percent of any insurance recoveries associated with hazardous waste remediation sites are assigned to our customers. The balance of any insurance recoveries (90%) are retained by us until we have been reimbursed for the 10% share of clean-up costs not included in rates. There also is a special sharing between our customers and us of the costs incurred pursuing recovery under insurance contracts. In connection with electricity industry restructuring, this mechanism may no longer be used to recover electricity generation-related clean-up costs for contamination caused by events occurring after January 1, 1998. We cannot provide assurance, however, that these costs will not be material, or that we will be able to recover our costs in the future.

Hazardous waste remediation costs in the future are likely to be significant. However, based on our past experience, we believe that we can recover most of these costs either in rates or through insurance claims.


	*Air Quality*

Our operations, most significantly our generation plants and natural gas pipeline operations, are subject to numerous air pollution control laws, including the Federal Clean Air Act and similar state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxide and particulate matter. Fossil fuel-fired electric utility plants and gas compressor stations used in our pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.

Various multi-pollutant initiatives have been introduced in the U.S. Senate and House of Representatives. These initiatives include limits on the emissions of nitrogen oxide, sulfur dioxide, mercury and carbon dioxide, and some would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules. Hearings on legislation to amend the federal Clean Air Act have been held in the U.S. Senate but not in the House of Representatives.

As a result of our divestiture of most of our fossil fuel-fired and geothermal generation facilities, our nitrogen oxide emission reduction compliance costs have been reduced significantly. Two of the local air districts

in which we own and operate fossil fuel-fired generation facilities have adopted final rules under the California Clean Air Act and the federal Clean Air Act that required reductions in nitrogen oxide emissions from the facilities of approximately 90% by 2004. We are in compliance with these rules. Several other air districts are considering nitrogen oxide rules that would apply to our natural gas compressor stations in California. Eventually, the rules are likely to require nitrogen oxide reductions of up to 80% at many of these natural gas compressor stations. Substantially all these costs will be capital costs which we expect to recover through rates.

In addition, current regulatory initiatives, particularly at the federal level, could increase our compliance costs and capital expenditures primarily with respect to our gas transportation facilities, fleet and fuel storage tanks, to comply with laws relating to emissions of carbon dioxide and other greenhouse gases, particulates and other toxic pollutants. If enacted, these laws could require us to replace equipment, install additional pollution controls, purchase various emission allowances, or curtail operations. Although associated costs and capital expenditures could be material, we expect that we would be able to recover these costs and capital expenditures in rates.


	*Water Quality*

The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the U.S. Environmental Protection Agency, or the EPA. Our generation facilities are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Our steam-electric generation facilities comply in all material respects with the discharge constituents standards and the thermal standards. In addition, under the federal Clean Water Act, we are required to demonstrate that the location, design, construction and capacity of generation facility cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts at our existing water-cooled thermal plants. We have submitted detailed studies of each steam-electric generation facility’s intake structure to various governmental agencies and each power plant’s existing intake structure was found to meet the best technology available requirements.

Our Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a National Pollutant Discharge Elimination System, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, recreation, commercial/sport fishing, marine and wildlife habitat, shellfish harvesting and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant’s discharge was not protective of beneficial uses.

In October 2000, we and the Central Coast Board reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that our discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology meets the best technology available requirements. As part of the Central Coast settlement, we have agreed to take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement. On June 17, 2003, the Central Coast settlement was executed by us, the Central Coast Board and the California Attorney General’s Office. A condition to the effectiveness of the Central Coast settlement is that the Central Coast Board renew Diablo Canyon’s NPDES permit. However, at its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported this settlement and the Central Coast Board requested its staff to develop additional information on possible mitigation measures. The California Attorney General filed a claim in our Chapter 11 proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with the Diablo Canyon power plant’s operation of its cooling water system. We are seeking withdrawal of this claim from our Chapter 11 proceeding.

In addition, on April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing electricity generation facilities using over 50 million gallons per day, typically including some form of “once-through” cooling. Our Diablo Canyon, Hunters Point and Humboldt Bay power plants are among an estimated 539 generation facilities nationwide that would be affected by this rulemaking. The proposed regulations call for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. The final regulations were issued in February 2004 and our initial review suggests that no material increased costs will result.


	*Endangered Species*

Many of our facilities and operations are located in or pass through areas that are designated as critical habitats for federal or state-listed endangered, threatened or sensitive species. We may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated near our facilities or operations. We are seeking to secure “habitat conservation plans” to ensure long-term compliance with the state and federal endangered species acts. We expect that we will be able to recover costs of complying with state and federal endangered species acts through rates.


	*Hazardous Waste Compliance and Remediation*

Our facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of our operations, we generate waste that falls within CERCLA’s definition of a hazardous substance and, as a result, have been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We assess, on an ongoing basis, measures that may be necessary to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. We have a comprehensive program to comply with hazardous waste storage, handling and disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous waste laws and other environmental requirements.

We have been, and may be, required to pay for environmental remediation at sites where we have been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where we store, recycle and dispose of potentially hazardous materials (or have done so in the past). Under federal and California laws, we may be responsible for remediation of hazardous substances even if we did not deposit those substances on the site.

Operations at our current and former generation facilities may have resulted in contaminated soil or groundwater. Although we sold most of our geothermal generation facilities and most of our fossil fuel-fired plants, in many cases we retained pre-closing environmental liability under various environmental laws. We are currently investigating or remediating several such sites with the oversight of various governmental agencies.

In addition, the federal Toxic Substances Control Act regulates the use, disposal and cleanup of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. During the 1980s, we initiated two major programs to remove from service all of the distribution capacitors and network transformers

containing high concentrations of PCBs. These programs removed the vast majority of PCBs existing in our electricity distribution system.

We are assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The lampblack and tar residues are byproducts of a process that we, our predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), our manufactured gas plants were removed from service. The residues that may remain at some sites contain chemical compounds that now are classified as hazardous. We own all or a portion of 28 manufactured gas plant sites. We have a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at these sites. We spent approximately $8 million in 2003 and expect to spend approximately $6 million in 2004 on these projects. We expect that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. In addition, approximately 68 other manufactured gas plants in our service territory are now owned by others. We have not incurred any significant costs associated with these non-owned sites, but it is possible that we may incur additional cleanup costs related to these sites in the future if hazardous substances for which we have liability are found.

In mid-January 2004, hexavalent chromium was detected in a sample taken from a groundwater monitoring well near our natural gas compressor station located in the area of California near Topock, Arizona. This monitoring well is located approximately 150 feet from the Colorado River. While hexavalent chromium had been detected during previous sampling of other monitoring wells located further from the river, previous samples from this well had not shown any detectable hexavalent chromium. We are cooperating with the California Department of Toxic Substances Control, or DTSC, other state agencies and appropriate federal agencies to develop a plan to ensure that the hexavalent chromium does not impact the Colorado River. Although implementation of the plan poses several technical and regulatory obstacles, we do not expect the outcome in this matter to have a material adverse effect on our results of operations or financial condition.

Under environmental laws such as CERCLA, we have been or may be required to take remedial action at third-party sites used for the disposal of waste from our facilities, or to pay for associated cleanup costs or natural resource damages. We are currently aware of nine sites where investigation or cleanup activities are currently underway. At the Geothermal Incorporated site in Lake County, California, we have been directed to perform site studies and any necessary remedial measures by regulatory agencies. At the Casmalia disposal facility near Santa Maria, California, we and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires us and the other parties to perform certain site investigation and mitigation measures.

In addition, we have been named as a defendant in several civil lawsuits in which plaintiffs allege that we are responsible for performing or paying for remedial action at sites that we no longer own or never owned. Remedial actions may include investigations, health and ecological assessments and removal of wastes.

The cost of environmental remediation is difficult to estimate. We record an environmental remediation liability when site assessments indicate remediation is probable and we can estimate a range of reasonably likely cleanup costs. We review our remediation liability quarterly for each site where it may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at similar sites and the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, we record the costs at the lower end of this range. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning our responsibility, the complexity of environmental laws and regulations and the selection of compliance alternatives. We estimate the upper end of the cost range using reasonably possible outcomes least favorable to us.

We had an undiscounted environmental remediation liability of approximately $314 million at December 31, 2003, and $331 million at December 31, 2002. During 2003, the liability was reduced by approximately $17 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The

approximately $314 million accrued at December 31, 2003, includes approximately $104 million related to the pre-closing remediation liability associated with divested generation facilities, and $210 million related to remediation costs for those generation facilities that we still own, natural gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that are either owned by us or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $314 million environmental remediation liability, approximately $147 million has been included in prior rate setting proceedings, and we expect that approximately $116 million will be allowable for inclusion in future rates. We also recover our costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of our ultimate obligations may be subject to refund to ratepayers.

Our undiscounted future costs could increase to as much as $422 million if the other potentially responsible parties are not financially able to contribute to these costs or the extent of contamination or necessary remediation is greater than anticipated. The $422 million amount does not include an estimate for the costs of remediation at known sites owned or operated in the past by our predecessor corporations for which we have not been able to determine whether liability exists.

The California Attorney General, on behalf of various state environmental agencies, filed claims in our Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most of these sites, remediation is ongoing in the ordinary course of business or we are in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the cleanup. Other sites identified in the California Attorney General’s claims may not, in fact, require remediation or cleanup actions. Our plan of reorganization provides that we intend to respond to these types of claims in the ordinary course of business and since we have not argued that our Chapter 11 proceeding relieves us of our obligations to respond to valid environmental remediation orders, we believe the California Attorney General’s claims seeking specific cash recoveries are unenforceable. Environmental claims in the ordinary course of business will not be discharged in our Chapter 11 proceeding and will pass through our Chapter 11 proceeding unimpaired.


	*Nuclear Fuel Disposal*

Under the Nuclear Waste Policy Act of 1982, or Nuclear Waste Act, the DOE is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more permanent disposal sites be in operation by 1998. Consistent with the law, we entered into a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from our nuclear power facilities beginning not later than January 1998. The DOE has been unable to meet its contractual commitment to begin accepting spent fuel. First, there was a delay in identifying a storage site. Then, after the DOE selected Yucca Mountain, Nevada for the site, protracted litigation has prevented the DOE from constructing the storage facility. The DOE’s current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. However, considerable uncertainty exists regarding when the DOE will begin to accept spent fuel for storage or disposal. Under our contract with the DOE, if the DOE completes a storage facility by 2010, the earliest Diablo Canyon’s spent fuel would be accepted for storage or disposal would be 2018.

On January 22, 2004, we filed separate complaints in the U.S. Court of Federal Claims against the DOE alleging that the DOE has breached its contractual obligation to move spent nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. The complaints seek recovery of our costs incurred for the planning and development of on-site storage at both facilities as a result of the DOE’s failure to meet its obligations. Our complaints are similar to complaints filed by at least 20 other utilities with nuclear facilities.

Under current operating procedures, we believe that the Diablo Canyon power plant’s existing spent fuel pools have sufficient capacity to enable it to operate through approximately 2007. It is unlikely that an interim or permanent DOE storage facility will be available by 2007. Therefore, we have applied to the NRC for a license

to build an on-site dry cask storage facility to store spent fuel at the Diablo Canyon power plant, pending disposal or storage at a DOE facility. The NRC has provided initial approvals for the facility and is expected to complete our authorization process in early 2004. We also have initiated the process for obtaining a required California Costal Commission permit for the facility. If the dry cask storage facility is not approved or is delayed, we also are pursuing NRC approval of another storage option to install a temporary rack in each unit that would increase the on-site storage capability to permit us to operate Unit 1 until 2010 and Unit 2 to 2011. During this additional period of time, we also would pursue NRC approval for a high density reracking of both units, which, if approved, would allow us to operate both units until shortly before the licenses expire in 2021 for Unit 1 and 2025 for Unit 2. If we are unsuccessful in permitting and constructing the on-site dry cask storage facility, and we are otherwise unable to increase our on-site storage capacity, it is possible that the operations of Diablo Canyon may have to be curtailed or halted until such time as spent fuel can be safely stored.

In July 1988, the NRC gave us final approval to store radioactive waste from our retired nuclear generating facility, Humboldt Bay Unit 3, on-site before decommissioning the unit is completed in 2015. We have agreed to remove all spent fuel when the federal disposal site is available. In 1988, we completed the first step in the decommissioning of Humboldt Bay Unit 3 and placed the unit into SAFSTOR, a condition of monitored safe storage in which the unit will be maintained until the spent nuclear fuel is removed from the spent fuel pool and the facility is dismantled. The used fuel assemblies currently are stored in metal racks submerged in a pool of water called a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concrete and lined with stainless steel.

We filed an application in December 2003 with the NRC seeking authorization to build an on-site dry cask storage facility at Humboldt Bay Unit 3. We plan to file an application with the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to a dry cask facility would allow early decommissioning of Humboldt Bay Unit 3. We anticipate that, if we were licensed to employ an on-site dry cask storage facility, we would receive a 20-year initial license for on-site dry cask storage with the opportunity to receive a 20-year renewal term.


	*Nuclear Decommissioning*

Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. Our nuclear power facilities consist of two units at the Diablo Canyon power plant and the retired facility at Humboldt Bay Unit 3. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2021 and to be completed in 2040, decommissioning of Diablo Canyon Unit 2 is scheduled to begin in 2025 and to be completed in 2041, and decommissioning of Humboldt Bay Unit 3 is scheduled to begin in 2006 and be completed in 2015.

The estimated nuclear decommissioning costs for the Diablo Canyon power plant and Humboldt Bay Unit 3 are approximately $1.83 billion in 2003 dollars (or approximately $5.25 billion in future dollars). These estimates are based on a 2002 decommissioning cost study prepared in accordance with CPUC requirements and used in our nuclear decommissioning costs triennial proceeding, discussed below. The decommissioning cost estimates are based on the plant location and cost characteristics for our nuclear plants. Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, costs of labor, materials and equipment.

The CPUC has established the nuclear decommissioning costs triennial proceeding to determine our estimated decommissioning costs and to establish the associated annual revenue requirement and escalation factors for consecutive three-year periods. In October 2003, the CPUC issued a decision in the 2002 nuclear decommissioning costs triennial proceeding (covering 2003 through 2005) finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the Diablo Canyon power plant’s eventual decommissioning. The decision also set the annual decommissioning fund revenue requirement for Humboldt Bay Unit 3 at approximately $18.5 million and granted our request to begin decommissioning Humboldt Bay Unit 3 in 2006 instead of 2015. The decision further granted our request of approximately $8.3 million for Humboldt Bay Unit 3 SAFSTOR operating and maintenance costs. The total adopted annual revenue requirement

of approximately $26.7 million represents a $4.5 million decrease from the previously adopted revenue requirement of approximately $31.2 million, which included amounts for both Humboldt Bay Unit 3 and Diablo Canyon. The CPUC also ordered us to partially fund our 2004 revenue requirement with approximately $10 million that we collected in rates in 2000 for our nuclear decommissioning revenue requirement but that we did not contribute to the trusts due to our cash conservation needs during the energy crisis.

Our revenue requirements for nuclear decommissioning costs are recovered from ratepayers through a nonbypassable charge that will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. We have three decommissioning trusts for our Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. We have elected that two of these trusts be treated under the Internal Revenue Code of 1986, as amended, or the Code, as qualified trusts. If certain conditions are met, we are allowed a deduction for the payments made to the qualified trusts. These payments cannot exceed the amount collected from ratepayers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts’ after-tax returns. Among other requirements, to maintain the qualified trust status, the IRS, must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. We cannot deduct amounts contributed to the non-qualified trust until the decommissioning costs are actually incurred.

In 2003, we collected approximately $22.6 million in rates and contributed approximately $21.3 million, on an after-tax basis, to the nuclear decommissioning trusts. For 2004, we are authorized to collect approximately $18.5 million in rates for decommissioning Humboldt Bay Unit 3. Of this amount, we expect to contribute approximately $13.3 million, on an after-tax basis, to the qualified and non-qualified trusts for Humboldt Bay Unit 3. We have requested the IRS approve the new amounts to be contributed to the qualified trusts for Humboldt Bay Unit 3. If the IRS does not approve the request, we must withdraw any contributions it made to the qualified trusts for 2003 and contribute the withdrawn amounts, on an after-tax basis, to the non-qualified trust. We would likely request that the CPUC approve an increase in revenue requirements to make up for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxes

The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling our nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. All earnings on the funds held in the trusts, net of authorized disbursements from the trusts and management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC. At December 31, 2003, we had accumulated decommissioning trust funds with an estimated fair value of approximately $1.4 billion, based on quoted market prices and net of deferred taxes on unrealized gains.


	*Electric and Magnetic Fields*

EMFs naturally result from the generation, transmission, distribution and use of electricity. In January 1991, the CPUC opened an investigation to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with EMFs from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMFs, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist.

In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. As part of our effort to educate the public about EMFs, we provide interested customers with information regarding the EMF exposure issue. We also provide a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.

In October 2002, the California Department of Health Services released its report, based primarily on its review of studies by others, evaluating the possible risks from EMFs, to the CPUC and the public. The report’s

conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health Services’ report has assigned a higher probability to the possibility that there is a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.

It is not yet clear what actions the CPUC will take to respond to this report. Possible outcomes include, but are not limited to, continuation of current policies and imposition of more stringent measures to mitigate EMF exposures. We cannot estimate the costs of such mitigation measures with any certainty at this time. However, such costs could be significant, depending on the particular mitigation measures undertaken, especially if we must ultimately relocate existing power lines.

We currently are not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs from power lines. The court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMFs are similarly barred. We were one of the defendants in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMFs. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs and barred plaintiffs’ personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case.

Legal Proceedings

In addition to the following legal proceedings, we are involved in various legal proceedings in the ordinary course of our business.

Pacific Gas and Electric Company vs. Michael Peevey, et al.

On November 8, 2000, we filed a lawsuit in the district court against the CPUC commissioners. In this lawsuit, we seek a declaration that the federally tariffed wholesale electricity costs that we had incurred to serve our customers are recoverable in retail rates under the federal filed rate doctrine.

Our complaint alleges that the wholesale electricity costs that we had prudently incurred are paid pursuant to filed tariffs that the FERC has authorized and approved, and that, under the U.S. Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. Our complaint also alleges that, to the extent that we are denied recovery of these wholesale electricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of our property. We argue that the CPUC’s decisions are preempted by federal law under the filed rate doctrine, which requires the CPUC to allow us to recover in full our reasonable purchase costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also asserts claims under the Commerce Clause and the Due Process Clause of the U.S. Constitution. On January 29, 2001, our lawsuit was transferred to the U.S. District Court for the Central District of California, or the central district court, where a similar lawsuit filed by SCE was pending. On May 2, 2001, the central district court dismissed our complaints without prejudice to re-filing at a later date, on the ground that the lawsuit was premature, since two CPUC decisions referenced in the complaint had not become final under California law. The court rejected all of the CPUC’s other arguments for dismissal of our complaint.

In August 2001, we re-filed our complaint in the district court based on our belief that the CPUC decisions referenced in the court’s May 2001 order had become final under California law. On October 31, 2001, the CPUC moved to dismiss the action. While the motion was under submission, the parties filed cross-motions for summary judgment.

On July 25, 2002, the district court denied the CPUC’s motion to dismiss on all grounds, as well as the parties’ motions for summary judgment. While the court agreed with our position that the filed rate doctrine applies to the federally-tariffed wholesale costs at which we had purchased electricity, it held that certain triable issues of fact precluded entry of summary judgment in our favor.

On August 23, 2002, the CPUC filed an appeal to the United States Circuit Court of Appeals for the Ninth Circuit, or the Ninth Circuit. Pursuant to our request, the district court certified the appeal as “wholly without merit and, therefore, frivolous,” and rejected the CPUC’s request to stay the proceedings. On November 21, 2002, the Ninth Circuit stayed the district court’s proceedings pending the CPUC’s appeal. The appeal was fully briefed and the Ninth Circuit heard oral argument on March 10, 2003.

Under the settlement agreement, we will dismiss the filed rate case with prejudice on or as soon as practicable after the later of the effective date of our plan of reorganization or the date on which CPUC approval of the settlement agreement is no longer subject to appeal. Therefore, we filed a motion to stay consideration of the appeal of the filed rate case. On August 11, 2003, the Ninth Circuit issued an order staying proceedings in the filed rate case. The Ninth Circuit has ordered the parties to file a status report by July 30, 2004.


	*In re: Natural Gas Royalties Qui Tam Litigation*

This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (referred to as a relator in the terminology of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including us. The cases were consolidated for pretrial purposes in the U.S. district court for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.

Under procedures established by the False Claims Act, the United States, acting through the Department of Justice, or DOJ, is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases.

The complaints allege that the various defendants, most of whom are natural gas pipeline companies or their affiliates, incorrectly measured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases.

The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties and reasonable expenses associated with the litigation. The relator has filed a claim in our Chapter 11 proceeding for $2.5 billion, $2.0 billion of which is based upon the relator’s calculation of penalties against us.

We believe the allegations to be without merit and intend to present a vigorous defense. We believe that the ultimate outcome of the litigation will not have a material adverse effect on our financial condition or results of operations.


	*Diablo Canyon Power Plant*

Our Diablo Canyon power plant employs a “once-through” cooling water system, which is regulated under a NPDES permit issued by the Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, our Diablo Canyon power plant’s discharge was not protective of beneficial uses.

In October 2000, we reached a tentative settlement of this matter with the Central Coast Board pursuant to which the Central Coast Board agreed to find that our discharge of cooling water from our Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available as defined in the Federal Clean Water Act. As part of the Central Coast settlement, we agreed to take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement. On June 17, 2003, the Central Coast settlement was executed by us, the Central Coast Board and the California Attorney General’s Office. A condition to the effectiveness of the

settlement is that the Central Coast Board renew Diablo Canyon’s NPDES permit. However, at its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the Central Coast settlement accepted in March 2003, and the Central Coast Board requested its staff to develop additional information on possible mitigation measures.

The California Attorney General has filed a claim in our Chapter 11 proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with the Diablo Canyon power plant’s operation of its cooling water system. We are seeking withdrawal of this claim.

On June 13, 2002, we received a draft enforcement order from the DTSC alleging that our Diablo Canyon power plant failed to maintain an adequate financial assurance mechanism to cover closure costs for its hazardous waste storage facility for several months after our Chapter 11 filing in 2001. The draft order sought $340,000 in civil penalties for the period during which we were unable to comply with the DTSC’s requirements. The draft order also directed us to maintain appropriate financial assurance on a going forward basis. On September 4, 2002, we received a draft enforcement order from DTSC alleging a variety of hazardous waste violations at our Diablo Canyon power plant. This draft order sought $24,330 in civil penalties.

In April 2003, we signed a final settlement agreement with DTSC, under which we agreed to pay approximately $165,000 in civil penalties and approximately $30,000 in costs. We paid these amounts in May 2003. The California Attorney General filed a claim in our Chapter 11 proceeding on behalf of DTSC and, in February 2004, withdrew those portions of the claim relating to financial assurance and hazardous waste matters.

We believe that the ultimate outcome of these matters will not have a material adverse impact on our financial condition or results of operations.


	*Compressor Station Chromium Litigation*

The following 14 civil suits are pending in several California courts against us relating to alleged chromium contamination: (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed January 30, 2001, in Los Angeles County Superior Court, (7) Fordyce v. Pacific Gas and Electric Company, filed March 16, 2001, in San Bernardino Superior Court, (8) Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (9) Alderson, et al. v. Corp, Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April 11, 2001, in Los Angeles County Superior Court, (10) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (11) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (12) Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernardino County Superior Court, (13) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court, and (14) Lytle v. Pacific Gas and Electric Company, filed March 22, 2002, in Yolo County Superior Court.

All of these civil actions are now pending in the Los Angeles Superior Court, except the Lytle case, which is pending in Yolo County. Currently there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals have filed proofs of claim in our Chapter 11 proceeding, most of whom are plaintiffs in the chromium litigation. Approximately 1,035 claimants have filed proofs of claim requesting approximately $580 million in damages and another approximately 225 claimants have filed claims for an “unknown amount.”

In general, plaintiffs and claimants allege that exposure to chromium at or near our gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona caused personal

injuries, wrongful death, loss of consortium, or other injury and seek related damages. The bankruptcy court has granted certain claimants’ motion for relief from stay so that the state court lawsuits pending before our Chapter 11 filing can proceed.

We are responding to the suits in which we have been served and are asserting affirmative defenses. We will pursue appropriate legal defenses, including the statute of limitations, exclusivity of workers’ compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.

To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from the Aguayo, Acosta and Aguilar cases for a test trial. Plaintiffs’ counsel selected ten of these initial trial plaintiffs, defense counsel selected seven of the plaintiffs, and one plaintiff and two alternates were selected at random. We have filed 13 summary judgment motions or motions in limine (motions to exclude potentially prejudicial information) challenging the claims of the trial test plaintiffs. Two of these motions are scheduled for hearing in the first quarter of 2004, with the others to be scheduled thereafter. The trial of the test cases is scheduled to begin in March 2004. Our motion to dismiss the complaint in the Adams case was granted. The plaintiffs in that case have until April 12, 2004 to file an amended complaint.

We have recorded a reserve in our financial statements in the amount of $160 million for these matters. We believe that, in light of the reserves that have already been accrued with respect to this matter, the ultimate outcome of this matter will not have a material adverse impact on our financial condition or future results of operations.


	*Complaints Filed by the California Attorney General, City and County of San Francisco and Cynthia Behr*

On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against Corp and its directors, as well as against our directors, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200, or Section 17200. Among other allegations, the California Attorney General alleged that past transfers of money from us to Corp, and allegedly from Corp to other affiliates of Corp, violated various conditions established by the CPUC in decisions approving the holding company formation. The California Attorney General also alleged that the December 2000 and January and February 2001 ringfencing transactions, by which Corp subsidiaries complied with credit rating agency criteria to establish independent credit ratings, violated the holding company conditions. On January 9, 2002, the CPUC issued a decision interpreting the holding company condition regarding capital requirements (which it terms the “first priority condition”) and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies “infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve.” The three major California investor-owned energy utilities and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The three major California investor-owned utilities and their parent holding companies appealed the CPUC’s interpretation of the first priority condition to various state appellate courts. The CPUC moved to consolidate all proceedings in the San Francisco state appellate court. The CPUC’s request for consolidation was granted and all the petitions are now before the California Court of Appeal for the First Appellate District in San Francisco, California. Oral argument is scheduled for March 5, 2004.

The complaint seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, civil penalties of $2,500 against each defendant for each violation of Section 17200, a total penalty of not less than $500 million and costs of suit. The California Attorney General’s complaint also seeks restitution of assets allegedly wrongfully transferred to Corp from us. In February 2002, Corp filed a notice of removal in the bankruptcy court to transfer the California Attorney General’s complaint to the bankruptcy court, as well as a motion to dismiss the lawsuit, or in the alternative, to stay the suit with the bankruptcy court. Subsequently, the California Attorney General filed a motion to remand the action to state court. In June 2002, the bankruptcy court held that federal law preempted the California Attorney General’s allegations concerning Corp’s participation in

our Chapter 11 proceedings. The bankruptcy court directed the California Attorney General to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties appealed the bankruptcy court’s June 2002 order to the district court.

On August 9, 2002, the California Attorney General filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning Corp’s participation in our Chapter 11 proceeding. Corp and the directors named in the complaint have filed motions to strike certain allegations of the amended complaint. On February 28, 2003, the court denied the three motions to strike on the grounds that they were premature and stated that it would defer making a judgment on the merits of the defendants’ arguments until the factual context of the cases was more fully developed.

On February 11, 2002, a complaint entitled City and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the California Attorney General’s complaint, including allegations of unfair competition. In addition, the complaint alleges causes of action for conversion, claiming that Corp “took at least $5.2 billion from the Utility,” and for unjust enrichment. The City seeks injunctive relief, the appointment of a receiver, payment to customers, disgorgement, the imposition of a constructive trust, civil penalties and costs of suit.

After removing the City’s action to the bankruptcy court in February 2002, Corp filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the bankruptcy court issued an Amended Order on Motion to Remand stating that the bankruptcy court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to us and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to state court. Both parties appealed the bankruptcy court’s remand order to the district court.

In addition, a third case, entitled Cynthia Behr v. PG&E Corporation, et al., was filed on February 14, 2002, by a private plaintiff (who also has filed a claim under Chapter 11) in Santa Clara Superior Court also alleging a violation of Section 17200. The Behr complaint also names the directors of Corp and us as defendants. The allegations of the complaint are similar to the allegations contained in the California Attorney General’s complaint, but also include allegations of conspiracy, fraudulent transfer and violation of the California bulk sales laws. The plaintiff requests the same remedies as the California Attorney General’s case, and, in addition, requests damages, attachment and restraints upon the transfer of defendants’ property. In March 2002, Corp filed a notice of removal in the bankruptcy court to transfer the complaint to the bankruptcy court. Subsequently, the plaintiff filed a motion to remand the action to state court. In its June 2002 ruling mentioned above as to the California Attorney General’s and the City’s cases, the bankruptcy court retained jurisdiction over Behr’s fraudulent transfer claim and bulk sales claim, finding them to belong to our estate. The bankruptcy court remanded Behr’s Section 17200 claim to the Santa Clara Superior Court. Both parties appealed the bankruptcy court’s remand order to the district court.

The San Francisco Superior Court has coordinated the California Attorney General’s case with the cases filed by the City and County of San Francisco and Cynthia Behr.

On July 24, 2003, the district court heard oral argument on the appeal and cross-appeal of the bankruptcy court’s remand order in the three cases. On October 8, 2003, the district court reversed, in part, the bankruptcy court’s June 2002 decision and ordered the California Attorney General’s restitution claims sent back to the bankruptcy court. The district court found that these claims, estimated along with the City and County of San Francisco’s claims at approximately $5 billion, are the property of our Chapter 11 estate and therefore are properly within the bankruptcy court’s jurisdiction. Under our plan of reorganization, we would release these claims. The district court also affirmed, in part, the bankruptcy court’s June 2002 decision and found that the California Attorney General’s civil penalty and injunctive relief claims under Section 17200 could be resolved in San Francisco Superior Court, where a status conference has been scheduled for April 21, 2004. The California Attorney General and the City and County of San Francisco have appealed this ruling to the Ninth Circuit. The defendants have filed motions to dismiss the appeals. No proceedings have been scheduled in bankruptcy court regarding the restitution claims. Under Section 17200, the California Attorney General is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. The

California Attorney General’s complaint asserted that the total civil penalties would be not less than $500 million. The bankruptcy court’s confirmation order provides that the California Attorney General’s and the City and County of San Francisco’s claims will not be released in connection with the implementation of our plan of reorganization.

The defendants filed a motion to seek clarification from the district court regarding whether the district court’s October 2003 order reaches the restitution claims against the director defendants, as distinct from Corp. At a hearing in November 2003, the district court confirmed that its October 2003 order holds that the defendants’ restitution claims against the directors are also the property of our estate.

MANAGEMENT

As of March 1, 2004, the names, ages and positions of the members of our board of directors and our executive officers were as follows:


Name	Age		Position

Robert D. Glynn, Jr.		61	Chairman of the Board
David R. Andrews		62	Director
Leslie S. Biller		55	Director
David A. Coulter		56	Director
C. Lee Cox		62	Director
William S. Davila		72	Director
David M. Lawrence, MD		63	Director
Mary S. Metz		66	Director
Carl E. Reichardt		72	Director
Barry Lawson Williams		59	Director
Gordon R. Smith		55	Director, President and Chief Executive Officer
Kent M. Harvey		45	Senior Vice President, Chief Financial Officer and Treasurer
Thomas B. King		42	Senior Vice President and Chief of Utility Operations
Roger J. Peters		53	Senior Vice President and General Counsel
Daniel D. Richard, Jr		53	Senior Vice President, Public Affairs
Gregory M. Rueger		53	Senior Vice President, Generation and Chief Nuclear Officer

Robert D. Glynn, Jr. has been Chairman of our board of directors since January 1998 and has been one of our directors since 1995. Mr. Glynn has been one of our officers since January 1988. Mr. Glynn also has been Chairman of the Board, Chief Executive Officer and President of Corp since January 1998. Mr. Glynn has been a director and officer of Corp since 1996.

David R. Andrews has been one of our directors and a director of Corp since 2000. Mr. Andrews is Senior Vice President Government Affairs, General Counsel and Secretary of PepsiCo, Inc. (food and beverage businesses), and has held that position since February 2002. Prior to joining PepsiCo, Mr. Andrews was a partner in the law firm of McCutchen, Doyle, Brown & Enersen, LLP from May 2000 to January 2002 and from 1981 to July 1997. From August 1997 to April 2000, he was the Legal Advisor to the U.S. Department of State and former Secretary Madeleine Albright. He also serves as a director of UnionBanCal Corporation.

Leslie S. Biller has been one of our directors and a director of Corp since 2004. Mr. Biller is retired Vice Chairman and Chief Operating Officer of Wells Fargo & Company (financial services and retail banking). He held that position from November 1998 until his retirement in October 2002. Mr. Biller was President and Chief Operating Officer of Norwest Corporation (bank holding company) from 1997 until it merged with Wells Fargo & Company in 1998. Mr. Biller has been our advisory director and an advisory director of Corp since January 2003. He also serves as a director of Ecolab Inc.

David A. Coulter has been one of our directors and a director of Corp since 1996. Mr. Coulter is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank, responsible for its investment bank, investment management and private banking, and has held that position since January 2001. Prior to the merger with J.P. Morgan & Co. Incorporated, he was Vice Chairman of The Chase Manhattan Corporation (bank holding company) from August 2000 to December 2000. He was a partner in the Beacon Group, L.P., (investment banking firm) from January 2000 to July 2000, and was Chairman and Chief Executive Officer of BankAmerica Corporation and Bank of America NT&SA from May 1996 to October 1998. He also serves as a director of Strayer Education, Inc.

C. Lee Cox has been one of our directors and a director of Corp since 1996. Mr. Cox is retired Vice Chairman of AirTouch Communications, Inc. and retired President and Chief Executive Officer of AirTouch

Cellular (cellular telephone and paging services). He was an executive officer of AirTouch Communications, Inc. and its predecessor, PacTel Corporation, from 1987 until his retirement in April 1997.

William S. Davila has been one of our directors since 1992 and a director of Corp since 1996. Mr. Davila is President Emeritus of The Vons Companies, Inc. (retail grocery). He was President of The Vons Companies from 1986 until his retirement in May 1992. He also serves as a director of The Home Depot, Inc.

David M. Lawrence, MD has been one of our directors since 1995 and a director of Corp since 1996. Dr. Lawrence is retired Chairman and Chief Executive Officer of Kaiser Foundation Health Plan, Inc. and Kaiser Foundation Hospitals, and was an executive officer of those companies from 1991 until his retirement in 2002. He also serves as a director of Agilent Technologies Inc. and McKesson Corporation.

Mary S. Metz has been one of our directors since 1986 and a director of Corp since 1996. Dr. Metz is President of S. H. Cowell Foundation, and has held that position since January 1999. Prior to that date, she was Dean of University Extension, University of California, Berkeley from July 1991 to June 1998. She also serves as a director of Longs Drug Stores Corporation, SBC Communications Inc. and UnionBanCal Corporation.

Carl E. Reichardt has been one of our directors since 1985 and a director of Corp since 1996. Mr. Reichardt served as Vice Chairman of Ford Motor Company from October 2001 to July 2003. He is retired Chairman of the Board and Chief Executive Officer of Wells Fargo & Company (bank holding company) and Wells Fargo Bank, N.A. He was an executive officer of Wells Fargo Bank, N.A. from 1978 until his retirement in December 1994. He also serves as a director of ConAgra Foods, Inc. and Ford Motor Company.

Barry Lawson Williams has been one of our directors since 1990 and a director of Corp since 1996. Mr. Williams is President of Williams Pacific Ventures, Inc. (business investment and consulting) and has held that position since 1987. He also served as interim President and Chief Executive Officer of the American Management Association (management development organization) from November 2000 to June 2001. He also serves as a director of CH2M Hill Companies, Ltd., The Northwestern Mutual Life Insurance Company, R.H. Donnelley Corporation, The Simpson Manufacturing Company Inc., and SLM Corporation.

Gordon R. Smith has been one of our directors since 1997. Mr. Smith also has been our President and Chief Executive Officer since June 1997. He has been one of our officers since June 1980. Mr. Smith also has been a Senior Vice President of Corp since January 1999.

Kent M. Harvey has been our Senior Vice President, Chief Financial Officer and Treasurer since July 1997. Mr. Harvey also was our Controller from January 2000 to October 2000.

Thomas B. King has been our Senior Vice President and Chief of Utility Operations since November 2003. Prior to his election, Mr. King was a Senior Vice President of Corp from January 1999 to October 2003.

Roger J. Peters has been our Senior Vice President since January 1999 and our General Counsel since July 1997. Mr. Peters also was our Vice President from July 1997 to December 1998.

Daniel D. Richard, Jr. has been our Senior Vice President of Public Affairs since May 1998. Mr. Richard was our Senior Vice President of Governmental and Regulatory Relations from July 1997 to April 1998. Mr. Richard also has been the Senior Vice President, Public Affairs of Corp since October 2000. He was Vice President of Governmental Relations of Corp from July 1997 to October 2000.

Gregory M. Rueger has been our Senior Vice President, Generation and Chief Nuclear Officer since April 2000. Mr. Rueger was our Senior Vice President and General Manager, Nuclear Power Generation Business Unit from November 1991 to April 2000.

All our directors serve until the next annual meeting of our shareholders, or until their successors are elected and qualified, except in the case of death, resignation or removal of the director. All our officers serve at the pleasure of our board of directors.

DESCRIPTION OF THE SENIOR SECURED BONDS

This prospectus describes certain general terms of the senior secured bonds, or senior bonds, that we may sell from time to time under this prospectus. We will describe the specific terms of each series of senior bonds we offer in a prospectus supplement. The senior bonds will be issued under an indenture of mortgage and one or more supplemental indentures that we will enter into with BNY Western Trust Company, as trustee. We refer to the indenture of mortgage, as supplemented by various supplemental indentures that we will enter into with the trustee, as the indenture. We have summarized selected provisions of the indenture and the senior bonds below. The information we are providing you in this prospectus concerning the senior bonds and the indenture is only a summary of the information provided in those documents, and the summary is qualified in its entirety by reference to the provisions of the indenture, including the forms of senior bonds attached thereto. You should consult the senior bonds themselves and the indenture for more complete information on the senior bonds as they, and not this prospectus or any prospectus supplement, govern your rights as a holder. The indenture is filed as an exhibit to the registration statement of which this prospectus is a part. The indenture will be qualified under the Trust Indenture Act of 1939, as amended, or the Trust Indenture Act, and the terms of the senior bonds will include those made part of the indenture by the Trust Indenture Act.

In this section, references to “we,” “our,” “ours” and “us” refer only to Pacific Gas and Electric Company and not to any of its direct or indirect subsidiaries or affiliates except as expressly provided.

General

After the effective date of our plan of reorganization, the indenture will constitute a first lien, subject to permitted liens, on substantially all of our real property and certain tangible personal property related to our facilities. The indenture does not limit the amount of debt that we may issue under it. However, prior to the release date, we may issue senior bonds under the indenture only on the basis of, and to the extent we have available, property additions, retired senior bonds and cash. In addition, prior to the release date, we may issue senior bonds under the indenture only if our net income for 12 consecutive calendar months during a specified period prior to the issuance of those senior bonds has not been less than two times our annual interest requirements. See “— Issuance of Additional Senior Bonds Prior to the Release Date.” The lien securing the senior bonds may be released in certain circumstances, subject to certain conditions. Upon release of the lien, the senior bonds will cease to be our secured obligations and will become our general unsecured obligations ranking pari passu with our other senior unsecured indebtedness. See “— Discharge of Lien; Release Date.” The senior bonds will be entitled to the benefit of the indenture equally and ratably with all other senior bonds issued under the indenture.

The prospectus supplement applicable to each issuance of senior bonds will specify, among other things:



	•	the title of the senior bonds;



	•	any limitation on the aggregate principal amount of the senior bonds;



	•	the price or prices at which we will sell the senior bonds;



	•	the date or dates on which the principal of any of the senior bonds is payable, including the maturity date, or how to determine those dates, and our right, if any, to extend those dates and the duration of any extension;



	•	the interest rate or rates of the senior bonds, if any, which may be fixed or variable, or the method or means by which the interest rate or rates are to be determined, and our ability to extend any interest payment periods and the duration of any extension;



	•	the date or dates from which any interest will accrue, the dates on which we will pay interest on the senior bonds and the regular record date, if any, for determining who is entitled to the interest payable on any interest payment date;



	•	any periods or periods within which, or date or dates on which, the price or prices at which and the terms and conditions on which the senior bonds may be redeemed, in whole or in part, at our option;



	•	any obligation of ours to redeem, purchase or repay any of the senior bonds pursuant to any sinking fund or other mandatory redemption provisions or at the option of the holder and the terms and conditions upon which the senior bonds will be so redeemed, purchased or repaid;



	•	the denominations in which we will authorize the senior bonds to be issued, if other than $1,000 or integral multiples of $1,000;



	•	whether we will offer the senior bonds in the form of global securities and, if so, the name of the depositary for any global securities;



	•	if the amount payable in respect of principal of or any premium or interest on any senior bonds may be determined with reference to an index or other fact or event ascertainable outside the indenture, the manner in which such amount will be determined;



	•	any events of default applicable to that series of senior bonds in addition to the events of default described under “— Events of Default;”


	•	covenants for the benefit of the holders of that series;


	•	the currency, currencies or currency units in which the principal, premium, if any, and interest on the senior bonds will be payable if other than U.S. dollars and the manner for determining the equivalent principal amount in U.S. dollars;



	•	provisions, if any, for exchange of the certificates representing the senior bonds or changes to the title and CUSIP number of the senior bonds to reflect the release of the lien of the indenture on the release date;



	•	if the principal of the senior bonds is payable from time to time without presentation or surrender, any method or manner of calculating the principal amount that is outstanding at any time for all purposes of the indenture; and



	•	any other terms of the senior bonds.

We may sell senior bonds at par or at a substantial discount below their stated principal amount. We will describe in a prospectus supplement material U.S. federal income tax considerations, if any, and any other special considerations for any senior bonds we sell that are denominated in a currency or currency unit other than U.S. dollars.

Redemption

Any terms for the optional or mandatory redemption of a series of senior bonds will be set forth in a prospectus supplement for the offered series. Unless otherwise indicated in a prospectus supplement, senior bonds will be redeemable by us only upon notice by mail not less than 30 nor more than 60 days before the date fixed for redemption and, if less than all the senior bonds of a series are to be redeemed, the particular senior bonds to be redeemed will be selected by the method provided for in the prospectus supplement for that particular series, or in the absence of any such provision, by the trustee in the manner it deems fair and appropriate.

We have reserved the right to provide conditional redemption notices for redemptions at our option or for redemptions that are contingent upon the occurrence or nonoccurrence of an event or condition that cannot be ascertained prior to the time we are required to notify holders of the redemption. A conditional notice may state that if we have not deposited redemption funds with the trustee or a paying agent on or before the redemption date or we have directed the trustee or paying agent not to apply money deposited with it for redemption of senior bonds, we will not be required to redeem the senior bonds on the redemption date.

Lien of the Indenture

General

facilities. We refer to property that is subject to the lien of the indenture as “mortgaged property” and property that is excepted from the lien of the indenture as “excepted property.” The lien securing the senior bonds may be released, however, in certain circumstances and subject to certain conditions. Upon release of the lien, the senior bonds will cease to be our secured obligations and will become our general unsecured obligations ranking pari passu with our other senior unsecured indebtedness. See “— Discharge of Lien; Release Date.”

The indenture provides that after-acquired property (other than after-acquired property qualifying as excepted property) located in the state of California will be subject to the lien of the indenture; provided, however, that in the case of a consolidation or merger (whether or not we are the surviving corporation) or the transfer or lease of all or substantially all of the mortgaged property, the indenture will not be required to be a lien upon any of the properties then owned or thereafter acquired by the successor corporation except properties acquired from us in or as a result of that transaction, to the extent not constituting excepted property, and improvements, extensions and additions to those properties and renewals, replacements and substitutions of or for any part or parts thereof. In addition, after-acquired property may be subject to liens existing or placed thereon at the time of acquisition thereof, including, but not limited to, purchase money liens, and, in certain circumstances, liens attaching to the property prior to the recording or filing of an instrument specifically subjecting the property to the lien of the indenture.

The indenture provides that before the release date, the trustee shall have a lien, prior to the senior bonds, on the mortgaged property and on all other property and funds held or collected by the trustee, other than property and funds held in trust for the payment of principal, premium, if any, and interest on the senior bonds, as security for the payment of the trustee’s reasonable compensation and expenses, and as security for the performance by us of our obligation to indemnify the trustee against certain liabilities.

Without the consent of the holders, we and the trustee may enter into supplemental indentures in order to subject additional property to the lien of the indenture (including property which would otherwise be excepted property). This property would thereupon constitute property additions (so long as it would otherwise qualify as property additions as described below) and be available as a basis for the issuance of additional senior bonds. See “— Issuance of Additional Senior Bonds Prior to the Release Date.”

See “— Discharge of Lien; Release Date” below for a discussion of the provisions of the indenture pursuant to which the lien of the indenture may be discharged and the senior bonds may become our unsecured obligations.

Excepted Property



	•	all money, investment property and deposit accounts (as those terms are defined in the California Commercial Code as in effect on the date of execution of the indenture), and all cash on hand or on deposit in banks or other financial institutions, shares of stock, interests in general or limited partnerships or limited liability companies, bonds, notes, other evidences of indebtedness and other securities, of whatever kind and nature, in each case to the extent not paid or delivered to, deposited with or held by the trustee;



	•	all accounts, chattel paper, commercial tort claims, documents, general intangibles (with certain exclusions such as licenses and permits to use the real property of others), instruments, letter-of-credit rights and letters of credit (as those terms are defined in the California Commercial Code) and all contracts, leases (other than the lease of certain real property at our Diablo Canyon power plant), operating agreements and other agreements of whatever kind and nature; all contract rights, bills and notes;



	•	all revenues, income and earnings, all accounts receivable, rights to payment and unbilled revenues, and all rents, tolls, issues, product and profits, claims, credits, demands and judgments, including any rights



		in or to rates, revenue components, charges, tariffs, or amounts arising therefrom, or in any amounts that are accrued and recorded in a regulatory account for collections by us;