Edgar Filing: PACIFIC GAS & ELECTRIC CO

e424b5

The information in this prospectus supplement is not complete and may be changed. Neither this prospectus supplement nor the accompanying prospectus is an offer to sell these securities and we are not soliciting offers to buy these securities in any jurisdiction where the offer or sale is not permitted.

Filed Pursuant to Rule 424(b)(5),

Registration No. 333-109994

PROSPECTUS SUPPLEMENT (Subject to Completion, dated March 12, 2004)

(To Prospectus dated March 5, 2004)

$6,700,000,000

(PACIFIC GAS AND ELECTRIC COMPANY LOGO)


	$ % First Mortgage Bonds due
	$ % First Mortgage Bonds due
	$ % First Mortgage Bonds due
	$ % First Mortgage Bonds due
	$ Floating Rate First Mortgage Bonds due

We are offering a total of $ aggregate principal amount of the first mortgage bonds referenced above, which we refer to collectively in this prospectus supplement as the “mortgage bonds.” We refer to the mortgage bonds that bear interest at a fixed rate as “fixed rate mortgage bonds” and we refer to the mortgage bonds that bear interest at variable rates as “floating rate mortgage bonds.” Interest on the fixed rate mortgage bonds will be payable semi-annually in arrears. Interest on the floating rate mortgage bonds will be payable quarterly in arrears and will be reset quarterly beginning on .

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

If the effective date of our plan of reorganization does not occur on or before , 2004, we must redeem all mortgage bonds at the redemption prices specified under “Description of the First Mortgage Bonds — Escrow of Proceeds and Mandatory Redemption.” Cash sufficient to effect this mandatory redemption of the mortgage bonds will be deposited into an escrow account on the closing date of this offering. After the effective date of our plan of reorganization, we may redeem the fixed rate mortgage bonds at our option at any time, in whole or in part, at the make whole redemption price specified under “Description of the First Mortgage Bonds — Optional Redemption,” and we may redeem the floating rate mortgage bonds at our option, in whole or in part, on , and on any interest payment date after that date, at 100% of the principal amount of the floating rate mortgage bonds being redeemed, plus any accrued and unpaid interest.

There is no existing public market for the mortgage bonds. We do not intend to list the mortgage bonds on any securities exchange or any automated quotation system.

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 supplement or the accompanying prospectus. Any representation to the contrary is a criminal offense.

Investing in the mortgage bonds involves risks. See “Risk Factors”

beginning on page 1 of the accompanying prospectus.






		Underwriting	Proceeds, Before Other
	Public Offering Price	Commission	Expenses, to Us


Per % First Mortgage Bond due	%	%	%
Total for % First Mortgage Bonds due	$	$	$

Per % First Mortgage Bond due	%	%	%
Total for % First Mortgage Bonds due	$	$	$

Per % First Mortgage Bond due	%	%	%
Total for % First Mortgage Bonds due	$	$	$

Per % First Mortgage Bond due	%	%	%
Total for % First Mortgage Bonds due	$	$	$

Per Floating Rate First Mortgage Bond due	%	%	%
Total for Floating Rate First Mortgage Bonds due	$	$	$

From , 2004, interest on the mortgage bonds will accrue and must be paid by the purchaser if the mortgage bonds are delivered after , 2004. The mortgage bonds are expected to be delivered on or about , 2004 through the book-entry facilities of The Depository Trust Company.


LEHMAN BROTHERS	UBS INVESTMENT BANK

CITIGROUP


BANC ONE CAPITAL MARKETS, INC.	CREDIT SUISSE FIRST BOSTON


ABN AMRO INCORPORATED	BARCLAYS CAPITAL	BNP PARIBAS	DEUTSCHE BANK SECURITIES


BNY CAPITAL MARKETS, INC.	BLAYLOCK & PARTNERS, L.P.	SIEBERT BRANDFORD SHANK & CO., LLC

, 2004.

TABLE OF CONTENTS


	Page

Prospectus Supplement
Special Note Regarding Forward-Looking Statements		ii
Summary		S-1
Use of Proceeds		S-10
Capitalization		S-11
Description of the First Mortgage Bonds		S-12
Description of Other Indebtedness		S-31
Certain United States Federal Income Tax Consequences		S-36
Ratings		S-39
Underwriting		S-39
Legal Matters		S-41
Prospectus
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		F-1

This prospectus supplement should be read in conjunction with the accompanying prospectus. You should rely only on the information contained in this prospectus supplement, the accompanying prospectus and the information incorporated by reference. Neither we nor any underwriter has authorized any other person to provide you with different or additional information. If anyone provides you with different or additional information, you should not rely on it. Neither we nor any underwriter is making an offer to sell the mortgage bonds in any jurisdiction where the offer or sale is not permitted. You should assume that the information contained in this prospectus supplement and the accompanying prospectus is accurate only as of the date thereof.

In connection with this offering, certain persons participating in this offering may engage in transactions that stabilize, maintain or otherwise affect the price of the mortgage bonds, including stabilization transactions or the covering of short positions. For a description of these activities, see “Underwriting.”

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus supplement, the accompanying prospectus and the documents incorporated by reference in the prospectus 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 conditions required to implement our plan of reorganization are satisfied;

	•	the impact of 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 with regard to allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposals 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 electricity purchase contracts allocated to our customers);

	•	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, or cause damage to our assets or 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 levels 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;

	•	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 nuclear 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 pattern 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 the accompanying prospectus titled “Risk Factors.”

You should read this prospectus supplement, the accompanying prospectus, the documents that we have filed as exhibits to the registration statement of which the accompanying prospectus is a part, and the documents that we refer to under the section of the accompanying 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. The forward-looking statements in this prospectus supplement speak only as of the date of this prospectus supplement. The forward-looking statements contained in the accompanying prospectus speak only as of the date of the 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.

iii

SUMMARY

The following information supplements, and should be read together with, the information contained in the accompanying prospectus. This summary highlights some information from this prospectus supplement and the accompanying prospectus, but it may not contain all the information that may be important to you in deciding whether to purchase the mortgage bonds offered by this prospectus supplement. You should read this entire prospectus supplement, the accompanying prospectus and the information incorporated by reference into the accompanying prospectus carefully before purchasing any mortgage bonds.

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 and natural gas distribution, electricity generation, electricity transmission, and natural gas transportation and storage. At December 31, 2003, our total assets were approximately $29.1 billion. Our weighted average rate base was approximately $14.5 billion during 2003.

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 gigawatt hours, or GWh, of electricity, which included approximately 8,978 GWh transmitted to direct access customers, and delivered approximately 804 billion cubic feet, or 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. Our weighted average distribution rate base was approximately $9.8 billion during 2003.

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 megawatts, or 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. Our weighted average generation rate base was approximately $1.6 billion during 2003.

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. Our weighted average electricity transmission rate base was approximately $1.6 billion during 2003.

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 weighted average natural gas transportation and storage rate base was approximately $1.5 billion during 2003.

The California Energy Crisis and Our Bankruptcy

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.

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dollars in defaulted debt and unpaid bills and caused us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code, or 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 a 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 proceeding under Chapter 11, or 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 Investors Service, or Moody’s, and at least BBB- by Standard and Poor’s, or 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. 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 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 also 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.

Pending Proceedings

On December 22, 2003, the bankruptcy court confirmed our plan of reorganization, fully incorporating the settlement agreement as a material and integral part of the plan. On January 5, 2004, the bankruptcy court denied a request for a stay of its confirmation order pending appeal and issued a decision approving the settlement agreement and overruling all objections to the confirmation of our plan of reorganization. Among other things, the bankruptcy court concluded that the CPUC was authorized to enter into the settlement agreement and to be bound by its terms. Following the bankruptcy court’s decision, the City of Palo Alto and the two CPUC commissioners who did not vote to approve the settlement agreement filed appeals of the bankruptcy court’s confirmation order with the U.S. District Court for the Northern District of California.

The CPUC approved the settlement agreement in a decision issued on December 18, 2003. On January 20, 2004, various parties to the CPUC proceedings filed applications for rehearing of the CPUC’s decision, challenging, among other things, the CPUC’s authority to execute the settlement agreement which by its terms would bind future commissions and subject the CPUC to the continuing jurisdiction of the bankruptcy court to enforce the agreement. The CPUC has placed consideration of these pending applications for rehearing on the agenda for its meeting on March 16, 2004. While we expect that the CPUC will reaffirm its earlier decision and deny these applications, there can be no assurance that it will take this action. If the CPUC denies rehearing, or has not acted on the applications by March 22, 2004, the applicants may seek judicial review of the CPUC’s decision by filing a petition with either a California court of appeal or the California Supreme Court. The issues

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on review must be limited to the issues raised in the applications for rehearing and no new or additional evidence can be introduced. We believe that the issues that have been raised in opposition to the CPUC decision would not cause a California appellate court to modify or set aside the settlement agreement and that even if such action were taken, the settlement agreement, once embodied in a final federal bankruptcy confirmation order, should be binding on the parties as a matter of federal law.

It is possible that, prior to the effective date of our plan of reorganization, one or more parties who are appealing the bankruptcy confirmation order or who are seeking rehearing of the CPUC decision approving the settlement agreement may file in the federal or state courts a request for a stay or other interim relief against the confirmation order or the CPUC decision. We believe that there are not sufficient legal grounds for obtaining a stay or other interim relief, and that the courts should deny any such requests.

Under applicable federal precedent, once our plan of reorganization has been “substantially consummated,” any pending appeals of the confirmation order should be dismissed. The sale of the mortgage bonds and the application of the proceeds from this offering, together with the other transactions our plan of reorganization contemplates will occur on the effective date of our plan of reorganization, should make the grant of effective relief by an appellate court impracticable, thereby rendering any appeal moot. However, on the closing date of this offering, our plan of reorganization will not yet be effective. As long as federal appeals of the confirmation order are still pending, there is a risk that a federal court, prior to “substantial consummation” of our plan, could stay, reverse or vacate the confirmation order and delay or prevent the effective date from occurring. As a result, we will deposit into an escrow account the gross proceeds from this offering, together with additional cash, sufficient to redeem the mortgage bonds if the effective date of our plan of reorganization does not occur on or before the 90th day after the closing of this offering.

Consummation of Our Plan of Reorganization

Implementation of our plan of reorganization remains subject to certain of the conditions described in the section of the accompanying prospectus titled “Description of Our Plan of Reorganization — Conditions to the Effectiveness of Our Plan of Reorganization,” including the consummation of the sale of the mortgage bonds and final CPUC approval of the settlement agreement. Although CPUC approval of the settlement agreement may be subject to pending appeals or further right of appeal in the event the CPUC has not acted on the applications for rehearing by March 22, 2004, we can satisfy the condition involving final CPUC approval of the settlement agreement by both us and Corp agreeing that approval on behalf of the CPUC, although subject to pending appeals or further right of appeal, constitutes final approval. When we complete the sale of the mortgage bonds, we expect that our and Corp’s determination as to final CPUC approval of the settlement agreement will be the sole remaining condition to be satisfied or waived. Our plan of reorganization provides that the effective date will occur 11 business days after all conditions are satisfied or waived.

Under a proposed technical modification to our plan of reorganization, the effective date must occur by May 15, 2004, although we are currently targeting the week of April 12, 2004. If our plan of reorganization becomes effective on or about April 12, 2004, we expect that the amount of allowed claims and transaction costs that we will pay and deposits into escrow accounts for disputed claims that we will make will total approximately $10.4 billion (including approximately $799 million to be used to repurchase, redeem or otherwise satisfy certain pollution control bonds and pollution control bond-related reimbursement obligations). We expect to use the proceeds from this offering, approximately $1.1 billion from our credit facilities and approximately $2.6 billion from our cash on hand to make these payments.

If, after our plan of reorganization has become effective and the proceeds of the offering of the mortgage bonds have been released to us and used to pay allowed claims in our Chapter 11 proceeding, and notwithstanding the federal precedent described above, the bankruptcy court’s confirmation order is subsequently overturned or modified, our ability to make payments on the mortgage bonds could be materially adversely affected.

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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.

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The Offering


Issuer		Pacific Gas and Electric Company

Mortgage Bonds		We are offering $ million aggregate principal amount of our % first mortgage bonds due , $ million aggregate principal amount of our % first mortgage bonds due , $ million aggregate principal amount of our % first mortgage bonds due , $ million aggregate principal amount of our % first mortgage bonds due and $ million aggregate principal amount of our floating rate first mortgage bonds due .

		Our floating rate first mortgage bonds due will bear interest at the three-month London interbank offered rate, or LIBOR, plus % per year.

Interest Payment Dates		Interest on the fixed rate mortgage bonds will be payable semi-annually in arrears on and of each year, commencing on , 2004, and at maturity.

		Interest on the floating rate mortgage bonds will be payable quarterly in arrears on , , and of each year, commencing on , 2004, and at maturity and will be reset quarterly, beginning on .

Ratings		The mortgage bonds are expected to be rated “ ” by Moody’s and “BBB” by S&P. Definitive debt ratings will not be assigned until the effective date of our plan of reorganization. For additional information regarding these ratings, see “Ratings.”

Ranking and Security		After the effective date of our plan of reorganization, the mortgage bonds will be secured by a first lien, subject to permitted liens, on substantially all of our real property and certain tangible personal property related to our facilities. Approximately $2.5 billion of additional bonds, issued under the same indenture as the mortgage bonds and ranking pari passu with the mortgage bonds, will be issued on the effective date of our plan of reorganization to provide security for other obligations.

		The lien may be released, however, in certain circumstances, subject to certain conditions. For additional information relating to the release of the lien of the indenture, see “Description of the First Mortgage Bonds — Discharge of Lien; Release Date.” Upon the release of the lien, the mortgage bonds and any other bonds that are issued under the indenture will cease to be our secured obligations and will become our unsecured general obligations ranking pari passu with our other unsecured indebtedness.

Escrow of Proceeds, Mandatory Redemption and Use of Proceeds		On the closing date of this offering, our plan of reorganization will not yet be effective. Therefore, on the closing date of this offering, we will deposit into an escrow account:

		• the gross proceeds from this offering;

		• cash in an amount equal to the maximum amount of interest that could accrue on the mortgage bonds to but not including the date of mandatory redemption; and

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		• cash sufficient to pay the redemption premiums of % on the % mortgage bonds due , % on the % mortgage bonds due , % on the % mortgage bonds due , % on the % mortgage bonds due and % on the floating rate mortgage bonds due .

		The amounts deposited into the escrow account will be released to us only if and when our plan of reorganization becomes effective, in which case we will use the funds to pay allowed claims under our plan of reorganization. If the effective date of our plan of reorganization does not occur on or before the 90th day after the closing date of this offering, the amounts deposited into the escrow account will be used to redeem all the mortgage bonds on the second business day after that 90th day at redemption prices equal to the principal amount of the mortgage bonds, plus accrued and unpaid interest from the closing date of this offering to but not including the date of mandatory redemption and the redemption premium on the applicable series of mortgage bonds.

Optional Redemption of the Fixed Rate Mortgage Bonds		After the effective date of our plan of reorganization, we may redeem each series of fixed rate mortgage bonds at any time prior to maturity, in whole or in part, at our option, at the redemption prices described under “Description of the First Mortgage Bonds — Optional Redemption.”

Optional Redemption of the Floating Rate Mortgage Bonds		After the effective date of our plan of reorganization, we may redeem the floating rate mortgage bonds, in whole or in part, at our option, on , and on any interest payment date after that date. The redemption price will be 100% of the principal amount of the floating rate mortgage bonds being redeemed, plus any accrued and unpaid interest to but not including the redemption date.

Additional Senior Bonds		Before the release of the lien of the indenture, we may issue additional senior bonds under the indenture only in amounts not exceeding 66 2/3% of the net amount of property additions and only if net income for a recent 12-month period is not less than two times our total annual interest requirements for the senior bonds taking into account the proposed interest on the additional senior bonds and for certain other senior secured debt. See “Description of the First Mortgage Bonds — Issuance of Additional Senior Bonds Prior to the Release Date.”

Covenants		We will issue the mortgage bonds under an indenture containing covenants that will limit our ability to, among other things:

		• merge or consolidate with another entity; and

		• convey, lease or otherwise transfer all or substantially all of our assets.

		In addition, if the mortgage bonds become unsecured obligations, the indenture will limit our and our significant subsidiaries’ ability to incur secured debt and enter into sale and leaseback transactions.

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		These covenants are subject to the qualifications and exceptions described under “Description of the First Mortgage Bonds — Restrictions on Liens and Sale and Leaseback Transactions” and “— Consolidation, Merger and Transfer of Mortgaged Property.”

Discharge of Mortgage Bonds		We will be deemed to have paid and will be discharged from any and all obligations for the mortgage bonds of a particular series if we take the required actions to discharge the mortgage bonds of that series.

Book-Entry, Delivery and Form		We will initially issue the mortgage bonds in the form of one or more global bonds for each series. On the closing date, we will deposit each global bond with, or for the account of, and we will register each global bond in the name of, The Depository Trust Company, or DTC, or its nominee. You may hold your beneficial interests in a global bond directly through DTC or indirectly through organizations that are participants in the DTC system.

Trustee		BNY Western Trust Company.

Governing Law		The indenture and the mortgage bonds will be governed by the laws of California.

Listing		The mortgage bonds will not be listed on any securities exchange or any automated quotation system.

Risk Factors		Purchase of the mortgage bonds involves risks and uncertainties. You should carefully consider the information contained and incorporated by reference in this prospectus supplement and the accompanying prospectus, including each of the factors described in the section of the accompanying prospectus titled “Risk Factors,” before deciding whether to purchase any mortgage bonds.

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Summary Consolidated Financial Data

The following table presents our summary consolidated financial data for the years ended December 31, 2003, 2002 and 2001. We derived the summary consolidated financial data for the years ended December 31, 2003, 2002 and 2001 from our audited consolidated financial statements included in the accompanying 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 included in the accompanying prospectus, the notes to those financial statements and the section of the accompanying prospectus titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”



			Year Ended December 31,

			2003			2002			2001


			(dollars in millions)
Consolidated Statements of Operations Data:
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:
	Depreciation, amortization and decommissioning			1,218			1,193			896
	Other operating expenses			6,881			5,408			7,088

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

Operating income				2,339			3,913			2,478
Interest expense(1)				(953	)		(988	)		(974	)
Other income				66			72			107
Income tax provision				(528	)		(1,178	)		(596	)

Net income from continuing operations			$	924		$	1,819		$	1,015

Other Data (unaudited):
Ratio of earnings to fixed charges(2)				2.51x			3.91x			2.58x
EBITDA(3)			$	3,623		$	5,178		$	3,481



	December 31,

	,
	2003		2002


	(in millions)
Consolidated Balance Sheet Data:
Cash and cash equivalents	$	2,979	$	3,343
Restricted cash		403		150
Working capital		3,555		3,399
Net property, plant and equipment		18,102		13,957
Total assets		29,066		24,593
Debt, classified as current		600		571
Long-term debt		2,431		2,739
Rate reduction bonds (excluding current portion)		870		1,160
Liabilities subject to compromise		9,502		9,408
Preferred securities with mandatory redemption provisions		137		137
Shareholders’ equity	$	5,089	$	4,194


(1)	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.

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(2)	For the purpose of computing ratios of earnings to fixed charges, “earnings” represent net income adjusted for income taxes and net 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 securities distribution requirements of our wholly owned trust.

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



		Year Ended December 31,

		2003			2002			2001


		(in millions)
Net income from continuing operations		$	924		$	1,819		$	1,015
Adjustments to reconcile EBITDA to net income from continuing operations:
	Depreciation, amortization and decommissioning		1,218			1,193			896
	Interest expense		953			988			974
	Income tax provision		528			1,178			596

EBITDA		$	3,623		$	5,178		$	3,481
Adjustments to reconcile EBITDA to net cash provided by operating activities:
	Cash paid for interest		(773	)		(1,105	)		(361	)
	Cash (paid) refunded for taxes		(648	)		(1,186	)		556
	Reversal of Independent System Operator accrual		—			(970	)		—
	Change in deferred charges and other non-current liabilities		581			102			(954	)
	Change in working capital (other than income taxes payable)		(653	)		363			2,379
	Payments authorized by bankruptcy court		(87	)		(1,442	)		(16	)
	Other, net		(73	)		194			(320	)

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

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USE OF PROCEEDS

On the closing date of this offering, our plan of reorganization will not yet be effective. Therefore, on the closing date, we will deposit into an escrow account:


	•	the gross proceeds from this offering;

	•	cash in an amount equal to the maximum amount of interest that could accrue on the mortgage bonds to but not including the date of mandatory redemption; and

	•	cash sufficient to pay the mandatory redemption premiums on the mortgage bonds.

The amounts deposited into the escrow account will be released to us only if and when our plan of reorganization becomes effective, in which case we will use these funds to pay allowed claims under our plan of reorganization.

If the effective date of our plan of reorganization does not occur on or before the 90th day after the closing date of this offering, the amounts deposited into the escrow account will be used to redeem all the mortgage bonds on the second business day after that 90th day at redemption prices equal to the principal amount of the applicable series of mortgage bonds, plus accrued and unpaid interest from the closing date of this offering to but not including the date of mandatory redemption and the redemption premium on the applicable series of mortgage bonds.

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CAPITALIZATION

The following table sets forth our cash and cash equivalents, long-term debt classified as current, and total capitalization as of December 31, 2003 on an actual basis and on an as adjusted basis to reflect the receipt of the proceeds from this offering, draws on our accounts receivable and other credit facilities and the payment of or provision for allowed claims under our plan of reorganization.

The information in this table should be read in conjunction with, and is qualified in its entirety by reference to, our consolidated financial statements included in the accompanying prospectus, the notes to those financial statements and the sections of the accompanying prospectus titled “Selected Consolidated Financial Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” See also “Description of Other Indebtedness.”



			As of December 31, 2003

			Actual		As Adjusted


			(in millions)
Cash and cash equivalents(1)			$	2,979	$	69

Long-term debt, classified as current:
	Current portion of long-term debt(2)			310		—
	Current portion of rate reduction bonds			290		290

	Total long-term debt, classified as current			600		290

Capitalization
	Financing under long-term credit facilities(3)			—		1,134
	Long-term debt			2,431		7,514
	Rate reduction bonds			870		870
	Financing debt subject to compromise(4)			5,603		—
	Preferred securities with mandatory redemption provisions(5)			137		127
	Shareholders’ equity(6)			5,089		5,089

		Total capitalization	$	14,130	$	14,734


(1)	Excludes restricted cash of $403 million in Actual December 31, 2003 balance. Restricted cash is expected to increase approximately $1.8 billion to reflect amounts deposited in escrow for disputed claims.

(2)	On March 1, 2004, we made an approximately $310 million principal payment on maturing first and refunding mortgage bonds.

(3)	We have established credit and accounts receivable facilities for the purpose of funding operating expenses and seasonal fluctuations in working capital and providing letters of credit, as well as term loan and reimbursement facilities to fund the repurchase, redemption or satisfaction of certain pollution control bonds and pollution control bond-related reimbursement obligations. We expect to use approximately $335 million from revolving credit or accounts receivable facilities and $799 million from the term loan and reimbursement facilities to pay allowed claims under our plan of reorganization. For more information regarding our credit and accounts receivable facilities, see “Description of Other Indebtedness” and the section of the accompanying prospectus titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Financial Resources.”

(4)	Excludes amounts owed to trade creditors subject to compromise of approximately $3.9 billion at December 31, 2003.

(5)	We will make a sinking fund payment of approximately $10 million on the effective date of our plan of reorganization.

(6)	Shareholders’ equity does not include any adjustments that might be required to record the $2.21 billion after-tax regulatory asset and the additional after-tax regulatory asset of approximately $800 million related to electricity generation assets. These regulatory assets will be recorded when the applicable accounting probability standard has been met. The $2.21 billion after-tax regulatory asset will be reduced for any refund, claim offsets or other credits we receive prior to its recognition.

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DESCRIPTION OF THE FIRST MORTGAGE BONDS

The first mortgage bonds represent five series of the senior secured bonds, or senior bonds, described under the section of the accompanying prospectus titled “Description of the Senior Secured Bonds.” The following information concerning the first mortgage bonds should be read in conjunction with the statements under “Description of the Senior Secured Bonds,” which the following information supplements and, in the event of any inconsistencies, supersedes. The following information does not purport to be complete and is subject to, and is qualified in its entirety by reference to, the terms of the indenture of mortgage, dated as of March 11, 2004, between us and BNY Western Trust Company, as trustee, and the first supplemental indenture thereto dated as of March , 2004, including the forms of the first mortgage bonds. We refer to the indenture of mortgage, as supplemented and to be supplemented by various supplemental indentures, as the “indenture.” The indenture is described in the accompanying prospectus and has been filed as an exhibit to the registration statement of which the accompanying prospectus is a part.

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

We are offering:


	•	$ million aggregate principal amount of % first mortgage bonds due ;

	•	$ million aggregate principal amount of % first mortgage bonds due ;

	•	$ million aggregate principal amount of % first mortgage bonds due ;

	•	$ million aggregate principal amount of % first mortgage bonds due ; and

	•	$ million aggregate principal amount of floating rate first mortgage bonds due .

We refer to these first mortgage bonds collectively as the mortgage bonds. We refer to the mortgage bonds that bear interest at a fixed rate as fixed rate mortgage bonds and we refer to the mortgage bonds that bear interest at variable rates as floating rate mortgage bonds.

The mortgage bonds will be issued in fully registered form only, without coupons. Each mortgage bond will be issued initially as a global bond in book-entry form and deposited with, or for the account of, The Depository Trust Company, or DTC, as securities depositary, or with the trustee on behalf of DTC. Except as set forth below under “— Book-Entry System; Global Bonds,” the mortgage bonds will not be issuable in certificated form. The authorized denominations of the mortgage bonds will be $1,000 and integral multiples thereof.

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. See “— Lien of the Indenture.” The lien securing the mortgage bonds may be released in certain circumstances, subject to certain conditions. Upon the release of the lien, the mortgage bonds will cease to be our secured obligations and will become our unsecured general obligations ranking pari passu with our other unsecured indebtedness. See “— Discharge of Lien; Release Date.” The mortgage bonds will be entitled to the benefit of the indenture equally and ratably with all other senior bonds issued under the indenture.

The indenture does not limit the amount of debt that we may issue under it. In addition, we may, from time to time and without the consent of the holders of the senior bonds, create and issue additional senior bonds of a series having the same ranking, interest rate, maturity and other terms as a series of senior bonds, except for the issue price, issue date and, in some cases, the first interest payment date. Any additional senior bonds having these similar terms will, together with the applicable series of senior bonds, constitute a single series of senior bonds under the indenture. However, prior to the date the lien of the indenture is released, or the release date, we may issue additional 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 additional senior bonds under the indenture only if our net income for 12 consecutive calendar months during a specified

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period prior to the issuance of those senior bonds has not been less than two times the annual interest requirements for the senior bonds taking into account the proposed interest on the additional senior bonds and for certain other senior secured debt. See “— Issuance of Additional Senior Bonds Prior to the Release Date.”

We will pay principal and interest on the mortgage bonds, register the transfer of mortgage bonds and exchange the mortgage bonds at our office or agency maintained for that purpose (which initially will be the office of the trustee located at 550 Kearny Street, Suite 600, San Francisco, California, 94108, Attention: Corporate Trust Administration). So long as the mortgage bonds are represented by global bonds, the interest payable on the mortgage bonds will be paid to Cede & Co., the nominee of DTC, or its registered assigns, as the registered owner of such global bonds, by wire transfer of immediately available funds on each of the applicable interest payment dates. If any of the mortgage bonds are no longer represented by a global bond, we have the option to pay interest by check mailed to the address of the person entitled to the interest or by wire transfer to registered holders of at least $10 million in principal amount of mortgage bonds at the place and to the account designated by those holders in writing to the trustee at least 16 days prior to the date for payment. No service charge will be made for any transfer or exchange of mortgage bonds, but we may require payment of a sum sufficient to cover any tax or other governmental charge payable.

Maturities, Interest Rates and Interest Payment Dates

Unless earlier redeemed:


	•	the % first mortgage bonds due mature on ;

	•	the % first mortgage bonds due mature on ;

	•	the % first mortgage bonds due mature on ;

	•	the % first mortgage bonds due mature on ; and

	•	the floating rate first mortgage bonds due mature on .

Interest on the mortgage bonds will be payable in U.S. dollars at:


	•	the fixed rate of % per annum with respect to the first mortgage bonds due ;

	•	the fixed rate of % per annum with respect to the first mortgage bonds due ;

	•	the fixed rate of % per annum with respect to the first mortgage bonds due ;

	•	the fixed rate of % per annum with respect to the first mortgage bonds due ; and

	•	a variable rate based on the three-month LIBOR, plus %, reset quarterly, beginning on , with respect to the floating rate first mortgage bonds due .

Interest on the mortgage bonds will:


	•	with respect to fixed rate mortgage bonds, be computed for each interest period on the basis of a 360-day year consisting of twelve 30-day months and for any period less than a full month, on the basis of the actual number of days elapsed during that period;

	•	with respect to floating rate mortgage bonds, be computed on the basis of the actual number of days in an interest period and a 360-day year;

	•	with respect to fixed rate mortgage bonds, be payable semi-annually in arrears on and of each year, commencing , and at maturity, to the holders of record at the close of business on the preceding and , respectively (except that interest that we pay on the maturity date will be payable to the person to whom the principal will be payable);

	•	with respect to floating rate mortgage bonds, be payable quarterly in arrears on , , and of each year, commencing , and at maturity, to the holders of record at the close of business on the preceding , ,

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		and , respectively (except that interest that we pay on the maturity date will be payable to the person to whom the principal will be payable); and

	•	originally accrue from, and include, the date of initial issuance.

If any interest payment date with respect to a fixed rate mortgage bond or the maturity date of any fixed rate mortgage bond falls on a day that is not a business day, the related payment of principal or interest will be made on the next succeeding business day as if made on the day the payment was due. No interest will accumulate on the amount payable for the period from and after that interest payment date or maturity date.

If any interest payment date with respect to a floating rate mortgage bond falls on a day that is not a business day, the related payment of interest will be made on the next succeeding business day as if made on the day the payment was due, unless the interest payment date falls in the next succeeding calendar month in which case the interest payment date will be the immediately preceding business day. If the maturity date of any floating rate mortgage bond falls on a day that is not a business day, the related payments of principal, premium, if any, and interest or other amounts may be made on the next succeeding business day, and no additional interest will accumulate on the amount payable for the period from and after the maturity date.

When we use the term “business day,” we mean any day except a Saturday, a Sunday or a legal holiday in the City of New York on which banking institutions are authorized or required by law, regulation or executive order to close; provided, with respect to determinations with respect to floating rate mortgage bonds, that the day is also a London business day. “London business day” means any day on which dealings in United States dollars are transacted in the London interbank market.

Interest on the floating rate mortgage bonds will accrue from, and including , to and excluding, the first interest payment date and then from, and including, the immediately preceding interest payment date to which interest has been paid or duly provided for to, but excluding, the next interest payment date or the maturity date, as the case may be. We refer to each of these periods as an “interest period.” The amount of accrued interest that we will pay for any interest period can be calculated by multiplying the face amount of the applicable floating rate mortgage bond by an accrued interest factor. This accrued interest factor is computed by adding the interest factor calculated for each day from , or from the last date we paid interest to you, to the date for which accrued interest is being calculated. The interest factor for each day is computed by dividing the interest rate applicable to that day by 360.

The interest rate on the floating rate mortgage bonds will be calculated by the calculation agent appointed by us. The interest determination date for an interest period will be the second London business day preceding the interest reset date. The interest reset dates are the dates on which the interest rates on the floating rate mortgage bonds will be reset, which are the same as the interest payment dates. Promptly upon determination of the interest rate, the calculation agent will inform the trustee of the interest rate for the next interest period. Absent manifest error, the determination of the interest rate by the calculation agent will be binding and conclusive on the holders of the floating rate mortgage bonds.

“LIBOR” will be determined by the calculation agent in accordance with the following provisions:


	•	With respect to any interest determination date, LIBOR will be the rate for deposits in United States dollars having a maturity of three months for a period commencing on the second London business day immediately following the interest determination date in amounts not less than $1 million, as that rate appears on Moneyline Telerate Page 3750 as of 11:00 a.m., London time, on that interest determination date. If no rate appears, then LIBOR, in respect to that interest determination date, will be determined in accordance with the provisions described in the following bullet point.

	•	With respect to an interest determination date on which no rate appears on Moneyline Telerate Page 3750, as specified in the bullet point above, the calculation agent will request the principal London offices of each of four major reference banks in the London interbank market, as selected by the calculation agent (after consultation with us), to provide the calculation agent with its offered quotation for deposits in United States dollars for the period of three months, commencing on the second London business day immediately following the interest determination date, to prime banks in the London interbank market at

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		approximately 11:00 a.m., London time, on that interest determination date and in a principal amount equal to an amount not less than $1 million that is representative for a single transaction in United States dollars in that market at that time. If at least two quotations are provided, then LIBOR on that interest determination date will be the arithmetic mean (rounded, if necessary, to the nearest one-hundred-thousandth of a percentage point (0.000001%) with five-millionths of a percentage point (0.0000005%) rounded upwards) of those quotations. If fewer than two quotations are provided, then LIBOR on the interest determination date will be the arithmetic mean (rounded, if necessary, to the nearest one-hundred-thousandth of a percentage point (0.000001%) with five-millionths of a percentage point (0.0000005%) rounded upwards) of the rates quoted at approximately 11:00 a.m., in the City of New York, on the interest determination date by three major banks in the City of New York selected by the calculation agent for loans in United States dollars to leading European banks, having a three-month maturity commencing on the second London business day immediately following the interest determination date and in a principal amount equal to an amount not less than $1 million that is representative for a single transaction in United States dollars in that market at that time; provided, however, that if the banks selected by the calculation agent are not providing quotations in the manner described by this sentence, LIBOR determined as of that interest determination date will be LIBOR in effect on that interest determination date.

“Moneyline Telerate Page 3750” means the display designated as “Page 3750” on Moneyline Telerate, or any successor service, for purpose of displaying the London interbank rates of major banks for United States dollars.

Escrow of Proceeds and Mandatory Redemption

Escrow of Proceeds

At the time of the closing of the offering of the mortgage bonds, our plan of reorganization will not yet be effective. Therefore, on or prior to the closing of the offering of the mortgage bonds, we will enter into an escrow agreement with BNY Western Trust Company, as escrow agent, pursuant to which we will deposit into an escrow account:


	•	the gross proceeds from this offering;

	•	cash in an amount equal to the maximum amount of interest that could accrue on the mortgage bonds to but not including the date of mandatory redemption, which date is the second business day after the 90th day after the closing date of this offering; and

	•	cash sufficient to pay the redemption premiums of:


	•	% on the % first mortgage bonds due ;

	•	% on the % first mortgage bonds due ;

	•	% on the % first mortgage bonds due ;

	•	% on the % first mortgage bonds due ; and

	•	% on the floating rate first mortgage bonds due .

We will only be entitled to direct the escrow agent to release the amounts deposited into the escrow account in accordance with the provisions of the escrow agreement. Pursuant to the escrow agreement, the escrow agent will release the escrowed proceeds upon receipt of an instruction certificate signed by us certifying that all conditions to effectiveness of our plan of reorganization have been satisfied or waived and that the effective date of our plan of reorganization has occurred. Upon release, we will use the funds deposited in the escrow account to pay allowed claims under our plan of reorganization.

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Mandatory Redemption

If the effective date of our plan of reorganization does not occur on or before the 90th day after the closing date of this offering, the amounts deposited into the escrow account will be used to redeem all the mortgage bonds on the second business day after that 90th day at redemption prices equal to the principal amount of the mortgage bonds, plus accrued and unpaid interest from the closing date to but not including the date of mandatory redemption plus the redemption premiums described above.

Optional Redemption

Fixed Rate Mortgage Bonds

After the effective date of our plan of reorganization, we may redeem fixed rate mortgage bonds of any series at any time prior to maturity, in whole or in part, at our option, at a redemption price equal to the greater of:


	•	100% of the principal amount of the applicable series of fixed rate mortgage bonds to be redeemed; or

	•	as determined by an independent investment banker, the sum of the present values of the remaining scheduled payments of principal and interest on the applicable series of fixed rate mortgage bonds to be so redeemed (not including any portion of the payments of interest accrued to the redemption date) discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the adjusted treasury rate, plus


	•	% in the case of the % first mortgage bonds due to be so redeemed;

	•	% in the case of the % first mortgage bonds due to be so redeemed;

	•	% in the case of the % first mortgage bonds due to be so redeemed; and

	•	% in the case of the % first mortgage bonds due to be so redeemed

plus, in all of the above cases, accrued and unpaid interest on the principal amount of the applicable series of fixed rate mortgage bonds being redeemed to but not including the redemption date.

For these purposes:


	•	“adjusted treasury rate” means, with respect to any optional redemption date for a series of fixed rate mortgage bonds:


	•	the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated “H.15(519) Selected Interest Rates” or any successor publication that is published weekly by the Board of Governors of the Federal Reserve System and that establishes yields on actively traded United States treasury securities adjusted to constant maturity under the caption “Treasury Constant Maturities” for the maturity corresponding to the comparable treasury issue (if no maturity is within three months before or after the remaining life, yields for the two published maturities most closely corresponding to the comparable treasury issue will be determined and the adjusted treasury rate will be interpolated or extrapolated from the yields on a straight line basis, rounding to the nearest month); or

	•	if the release (or any successor publication) is not published during the week preceding the calculation date or does not contain these yields, the rate per annum equal to the semi-annual equivalent yield to maturity of the comparable treasury issue (expressed as a percentage of its principal amount) equal to the comparable treasury price for the redemption date.


	•	“comparable treasury issue” means the United States treasury security selected by an independent investment banker as having a maturity comparable to the remaining life of the applicable series of fixed rate mortgage bonds to be redeemed that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining life of the applicable series of fixed rate mortgage bonds to be redeemed.

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	•	“comparable treasury price” means, with respect to any redemption date on which any series of fixed rate mortgage bonds is being redeemed, (a) the average of five reference treasury dealer quotations for the redemption date, after excluding the highest and lowest reference treasury dealer quotations, or (b) if the independent investment banker obtains fewer than five such reference treasury dealer quotations, the average of all quotations obtained.

	•	“dealer” means a primary U.S. government securities dealer in the United States.

	•	“independent investment banker” means one of the reference treasury dealers appointed by us.

	•	“reference treasury dealer” means each of Lehman Brothers Inc. and UBS Securities LLC and primary dealers in U.S. treasury securities acceptable to the independent investment banker and their respective successors; provided, however, that if any of the foregoing shall cease to be a dealer, we will select a substitute dealer. However, if we do not select a substitute dealer within a reasonable period of time, then the substitute dealer will be selected by the trustee after consultation with us.

	•	“reference treasury dealer quotations” means, with respect to each reference treasury dealer and any redemption date, the average, as determined by the independent investment banker, of the bid and asked prices for the comparable treasury issue (expressed in each case as a percentage of its principal amount) quoted in writing to the independent investment banker at 5:00 p.m., New York City time, on the third business day preceding the redemption date.

	•	“remaining life,” as of any date of calculation, means the remaining term of the applicable series of fixed rate mortgage bonds.

	•	“remaining scheduled payments” means, with respect to each fixed rate mortgage bond that we are redeeming, the remaining scheduled payments of principal and interest that would be due after the applicable redemption date if that fixed rate mortgage bond were not redeemed. However, if the redemption date is not a scheduled interest payment date with respect to that fixed rate mortgage bond, the amount of the next succeeding scheduled interest payment on that fixed rate mortgage bond will be reduced by the amount of interest accrued on that fixed rate mortgage bond to the redemption date.

Floating Rate Mortgage Bonds

After the effective date of our plan of reorganization, we may redeem the floating rate mortgage bonds, in whole or in part, at our option, on , and on any interest payment date after that date. The redemption price will be 100% of the principal amount of the floating rate mortgage bonds being redeemed, plus any accrued and unpaid interest to but not including the redemption date.

Partial Redemptions

If we redeem only some of the mortgage bonds of a series, DTC’s practice is to choose by lot the amount to be redeemed from the mortgage bonds held by each of its participating institutions. DTC will give notice to these participants, and these participants will give notice to any “street name” holders of any indirect interests in the mortgage bonds according to arrangements among them. These notices may be subject to statutory or regulatory requirements. We will not be responsible for giving notice of a redemption of the mortgage bonds to anyone other than DTC. If the series of mortgage bonds to be redeemed is no longer held through DTC and fewer than all the mortgage bonds of the series are to be redeemed, selection of mortgage bonds of a series for redemption will be made by the trustee in any manner the trustee deems fair and appropriate.

Rights of Redeemed Mortgage Bonds

Unless we default on payment of the redemption price, from and after the redemption date, the mortgage bonds to be redeemed will cease to accrue interest, and the holders of those mortgage bonds will have no right in respect of those mortgage bonds, except the right to receive the redemption price and any accrued and unpaid interest to the redemption date.

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Sinking Fund

There is no provision for a sinking fund for the mortgage bonds.

Lien of the Indenture

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. 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.” See the section of the accompanying prospectus titled “Description of the Senior Secured Bonds — Lien of the Indenture — Excepted Property” for a description of the excepted property and permitted liens.

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.”

The lien of the indenture may be released, however, in certain circumstances and subject to certain conditions. Upon the release of the lien, the mortgage bonds and all other senior bonds will cease to be our secured obligations and will become our unsecured general obligations ranking pari passu with our other unsecured indebtedness. See “— Discharge of Lien; Release Date.”

Release of Mortgaged Property

We may release property from the lien of the indenture if we deliver to the trustee cash equal to the funded property basis of the property to be released, less any taxes and expenses incidental to any sale, exchange, dedication or other disposition of the property to be released. Any of the following or any combination of the following will be applied as a credit against the cash we will be required to deliver to the trustee:


	•	the aggregate principal amount of obligations secured by a purchase money lien on the property to be released, subject to certain limitations described below;

	•	an amount equal to the net cost or net fair value to us (whichever is less) of certified property additions constituting unfunded property after certain deductions and additions, primarily including adjustments to offset property retirements (except that the adjustments need not be made if the property additions were acquired, made or constructed within 90 days before our request for release);

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	•	an amount equal to 150% of the aggregate principal amount of senior bonds we would be entitled to issue on the basis of retired senior bonds (with that entitlement being waived by operation of such release); and

	•	an amount equal to 150% of the aggregate principal amount of outstanding senior bonds delivered to the trustee.

“Funded property basis” generally means the net cost of funded property or the net fair value to us of the funded property at the time it became funded property, whichever is less.

“Net cost” means, as of the date of calculation, the cost of the property, less the lesser of (i) the outstanding principal amount of any senior lien obligations as of the date of calculation or (ii) the cost of the property.

“Net fair value” means, as of the date of calculation, the fair value of the property, less the lesser of (i) the outstanding principal amount of any senior lien obligations as of the date of calculation or (ii) the fair value of the property.

“Purchase money lien” means, generally, with respect to any property being acquired or disposed of by us or being released from the lien of the indenture, a lien on that property which (a) is taken or retained by the transferor of that property to secure all or part of its purchase price, (b) is granted to one or more persons other than the transferor, that, by making advances or incurring an obligation, give value to enable the grantor of the lien to acquire rights in or the use of the property, or (c) is granted to any other person in connection with the release of the property from the lien of the indenture on the basis of the deposit with the trustee of obligations secured by the lien on that property (as well as any other property subject to the lien), (d) is held by a trustee or agent for the benefit of one or more persons described in the preceding clauses (a), (b) and/or (c), or (e) otherwise constitutes a purchase money mortgage or purchase money security interest under applicable law.

We will be permitted to release from the lien of the indenture “unfunded property” (mortgaged property that has not been used as the basis for the issuance of senior bonds (not otherwise retired) or as the basis for the release or substitution of mortgaged property or the release of cash described below under “— Withdrawal of Cash” under the indenture) without depositing any cash with the trustee or providing any other credits if either (i) the lower of the net cost or net fair value to us of all unfunded property (excluding the property to be released), after making certain adjustments, is at least zero, or (ii) the lower of the net cost or net fair value to us of the unfunded property to be released, after making certain adjustments, does not exceed the lower of the net cost or net fair value of all property acquired, made or constructed on or after 90 days before our request, after making certain adjustments. If neither (i) or (ii) in the immediately preceding sentence applies, we will be required to deliver a “make-up” amount in cash. We may apply as a credit against the cash we will be required to deliver to the trustee any of the amounts described under the third and fourth bullet points in this section.

We also will be permitted to release in a calendar year property up to the greater of $10 million (increased yearly by the urban CPI) and 3% of the aggregate principal amount of senior bonds then outstanding without complying with the other release provisions in the indenture. However, if, upon reliance on this release provision, we release funded property, we are required to deposit with the trustee, by the end of the calendar year, cash equal to 66 2/3% of the funded property basis of the property released, net of certain credits.

The indenture provides simplified procedures for the release of property taken by eminent domain, and provides for dispositions of certain obsolete property and grants or surrender of certain rights without any release or consent by the trustee.

The provisions described above permitting the release of property (except property taken by eminent domain) will be operable only if no event of default has occurred and is continuing under the indenture.

Withdrawal of Cash

Unless an event of default has occurred and is continuing and subject to certain limitations, cash held by the trustee prior to the release date may, generally,


	•	be withdrawn by us (i) to the extent of an amount equal to the net cost or net fair value to us (whichever is less) of property additions constituting unfunded property, after certain deductions and additions,

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		primarily including adjustments to offset retirements (except that these adjustments need not be made if the property additions were acquired or made within 90 days before our request for withdrawal) or (ii) in an amount equal to 150% of the aggregate principal amount of senior bonds that we would be entitled to issue on the basis of retired senior bonds (with the entitlement to that issuance being waived by operation of the withdrawal) or (iii) in an amount equal to 150% of the aggregate principal amount of any outstanding senior bonds delivered to the trustee; or

	•	upon our request, be applied to (i) the purchase of senior bonds or (ii) the payment (or provision for payment) at stated maturity of any senior bonds or the redemption (or provision for redemption) of any senior bonds which are redeemable.

Discharge of Lien; Release Date

Subject to the conditions described below, we may, without the consent of the holders of the senior bonds, eliminate all terms and conditions relating to collateral for the senior bonds, with the result that our obligations under the indenture and senior bonds, including all mortgage bonds, would be entirely unsecured. We refer to the date on which the elimination of collateral occurs as the “release date.” The release date will be a date chosen by us and specified in an order signed by us and delivered to the trustee, which date shall not be earlier than the date of delivery by us to the trustee of each of the following:


	•	written evidence that the ratings on our long-term unsecured debt obligations, immediately after the release date, shall be at least equal to the initial ratings assigned by Moody’s and by S&P on the mortgage bonds or, if either or both of these rating agencies do not then rate our long-term unsecured debt obligations, comparable ratings by any other nationally recognized rating agency or agencies selected by us;

	•	a certificate signed by one of our authorized officers stating that the aggregate principal amount of debt secured by a lien on any principal property that will be outstanding immediately after the release date (excluding permitted secured debt described under “— Restrictions on Liens and Sale and Leaseback Transactions” below) will not exceed 5% of our net tangible assets as determined by us as of a month end not more than 90 days prior to the release date;

	•	a company order requesting execution and delivery by the trustee of a supplemental indenture (which may amend and restate the indenture) and those instruments that we may deem necessary or desirable to discharge, cancel, terminate or satisfy the lien of the indenture; and

	•	a certificate signed by one of our authorized officers stating that, to the knowledge of the signer, no event of default under the indenture has occurred and is continuing.

“Net tangible assets” for this purpose means the total amount of our assets determined on a consolidated basis in accordance with GAAP, less the sum of our consolidated current liabilities determined in accordance with GAAP and the amount of our consolidated assets classified as intangible assets determined in accordance with GAAP, including, but not limited to, such items as goodwill, trademarks, trade names, patents and unamortized debt discount and expense and regulatory assets carried as an asset on our consolidated balance sheet.

As promptly as practicable after the occurrence of the release date, we will give notice to all holders of senior bonds of the occurrence of the release date in the same manner as a notice of redemption and disseminate a press release through a public medium as is customary announcing that the lien of the indenture has been released as of the release date. After the release date, we will amend the indenture to eliminate the provisions related to liens (other than the restrictions described below under “— Restrictions on Liens and Sale and Leaseback Transactions”). In addition, after the release date, the names of the mortgage bonds will be changed from “first mortgage bonds” to “senior notes.”

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Issuance of Additional Senior Bonds Prior to the Release Date

Prior to the release date, we may issue senior bonds of any series from time to time against property additions, retired senior bonds and cash deposited with the trustee, in an aggregate principal amount not exceeding:


	•	66 2/3% of the aggregate of the net amounts of property additions which constitute “unfunded property” (mortgaged property which has not previously been used as the basis for the issuance of senior bonds (not otherwise retired) or as the basis for the release or substitution of mortgaged property or the release of cash discussed under “— Withdrawal of Cash”);

	•	the aggregate principal amount of retired senior bonds; and

	•	the amount of cash deposited with the trustee.

“Property additions” generally include any item, unit or element of property which is owned by us and is subject to the lien of the indenture except (with certain exceptions) goodwill, going concern value rights or intangible property, or any property the cost of acquisition or construction of which is properly chargeable to one of our operating expense accounts at the time of such acquisition or construction.

The indenture includes limitations on the issuance of senior bonds against property subject to certain senior liens and upon the increase of the amount of certain senior liens on funded property.

“Funded property” means, generally, mortgaged property which has been used as the basis for the issuance of senior bonds or as the basis for the release or substitution of mortgaged property under the indenture or as the basis for the release of cash.

“Retired senior bonds” means, generally, previously issued senior bonds which have been canceled or which we have delivered to the trustee for cancellation or previously issued senior bonds deemed to have been paid under the indenture, which have not been retired by the application of funded cash and which have not been used as the basis for the authentication and delivery of senior bonds, the release of property or the withdrawal of cash.

Prior to the release date and except with respect to the issuance of the mortgage bonds, we also must deliver a net earnings certificate showing that our net income for 12 consecutive calendar months within the 18 calendar months immediately before the first day of the month in which we request authentication and delivery of the senior bonds has been not less than two times our annual interest requirements.

“Net income” means:


	•	our operating revenues (which may include our revenues subject to possible refund at a future date);

		less

	•	our expenses, excluding (i) expenses for taxes paid or accrued on income or profits and other taxes measured by, or dependent on, net income, (ii) provisions for reserves for renewals, replacements, depreciation, amortization, depletion or retirement of property (or any expenditures therefor), (iii) expenses or provisions for interest on any of our indebtedness (including interest on capital lease obligations), for the amortization of debt discount, premium, expense or loss on reacquired debt, for amortization of payments made on swap agreements, for any maintenance and replacement, improvement or sinking fund or other device for the retirement of any indebtedness, or for other amortization, (iv) expenses, losses or provisions for any non-recurring or extraordinary charge to income or to retained earnings of whatever kind or nature (including, without limitation, the recognition of expense or impairment due to the non-recoverability of assets or expense, charges for changes in accounting principles recorded in accordance with GAAP and non-cash writedowns, book losses or other charges), or non-recurring charges, whether or not recorded as a non-recurring or extraordinary charge in our books of account, and (v) provisions for any refund of revenues previously collected or accrued by us subject to possible refund;

		plus

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	•	our other income, net of related expenses (excluding non-recurring charges, whether or not recorded as non-recurring or extraordinary charges in our books of account), including, but not limited to, non-utility operating income, cash distributions of our subsidiaries, any allowance for funds used during construction, and including any portion of the allowance, or of any analogous amounts, not included in “other items” (or any analogous item) in our books of account, other deferred costs (or any analogous amounts) in our books of accounts and any amounts collected by others to be applied to debt service on our indebtedness, and not otherwise treated on our books as revenue.

“Annual interest requirements” means the interest requirements for one year, at the respective stated interest rates, if any, borne prior to maturity, upon:


	•	all senior bonds then outstanding under the indenture at the date of the certificate (excluding any senior bonds that will be repaid or redeemed through senior bonds of any series or tranche described in the next bullet point); provided, however, that, if outstanding senior bonds bear interest at a variable rate or rates, then the interest requirement on the senior bonds of the series or tranche will be determined by reference to the rate or rates in effect two business days before the date of the certificate;

	•	the senior bonds for which the net earnings certificate is then being delivered (and any other pending issuance); provided, however, that if senior bonds of any series or tranche are to bear interest at a variable rate or rates, then the interest requirement of that series or tranche will be determined by reference to the rate or rates to be in effect at the time of the initial authentication and delivery or, if such rate or rates are not determinable at such time, then by reference to our good faith estimate of the rate or rates to be in effect at the time of the initial authentication and delivery of such senior bonds; and provided, further, that the determination of the interest requirement on senior bonds of a series subject to a periodic offering will be further subject to the other provisions described in the indenture; and

	•	the principal amount of all other indebtedness secured by a senior lien upon the mortgaged property or any part thereof (except (i) our indebtedness the repayment of which supports or is supported by other indebtedness included in annual interest requirements described in one of the two bullet points above, (ii) indebtedness outstanding on the date of the net earnings certificate secured by a prepaid lien (as defined in the indenture) upon mortgaged property outstanding on that date and secured by a lien on a parity with or prior to the lien of the indenture upon mortgaged property and (iii) our indebtedness that will be repaid or redeemed through senior bonds described in the preceding bullet point), if we have issued, assumed or guaranteed the indebtedness or if we customarily pay the interest upon the principal thereof; provided, however, that if the indebtedness bears interest at a variable rate or rates, then the interest requirement will be determined by reference to the rate or rates in effect two business days immediately before the date of the certificate.

If, when we make any net earnings certificate, any of our property (i) has been acquired during or after any period for which our net income is computed, (ii) has not been acquired in exchange or substitution for property the net earnings of which have been included in our net income and (iii) had been operated as a separate unit and items of revenue and expense attributable thereto are readily ascertainable by us, then the net earnings of that property (computed in the manner consistent with the computation of our net income) during that period or part of that period before its acquisition, to the extent that the same have not otherwise been included in our net income, will be included.

Evidence to be Furnished to the Trustee Under the Indenture

We will demonstrate compliance with indenture provisions by providing written statements to the trustee from our officers or persons we select. For instance, we may select an engineer to provide a written statement regarding the value of property being certified or released or counsel regarding compliance with the indenture generally. In certain major matters, applicable law requires that an accountant, engineer or other expert must be independent. We must file a certificate each year with respect to our compliance with the conditions and covenants under the indenture.

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Restrictions on Liens and Sale and Leaseback Transactions

From and after the release date, we will not, nor will we permit any of our significant subsidiaries to, (i) issue, incur, assume or permit to exist any debt secured by a lien on any of our principal property or on any principal property of any of our significant subsidiaries (whether that principal property is owned as of the date of execution of the indenture or thereafter acquired), unless we provide that the senior bonds will be equally and ratably secured with the debt or (ii) incur or permit to exist any attributable debt in respect of any principal property; provided, however, that the foregoing restriction will not apply to the following:


	•	to the extent we or a significant subsidiary consolidates with, or merges with or into, another entity, liens on the property of the entity securing debt in existence on the date of the consolidation or merger, provided that the debt and liens were not created or incurred in anticipation of the consolidation or merger and that the liens do not extend to cover any of our or a significant subsidiary’s principal property;

	•	liens existing on property acquired after the date of execution of the indenture, as long as the lien was not created or incurred in anticipation thereof and does not extend to or cover any of our or a significant subsidiary’s other principal property;

	•	liens of any kind, including purchase money liens, conditional sales agreements or title retention agreements and similar agreements, upon any property acquired, constructed, developed or improved by us or a significant subsidiary (whether alone or in association with others) which do not exceed the cost or value of the property acquired, constructed, developed or improved and which are created prior to, at the time of, or within 12 months after the acquisition (or in the case of property constructed, developed or improved, within 12 months after the completion of the construction, development or improvement and commencement of full commercial operation of the property, whichever is later) to secure or provide for the payment of any part of the purchase price or cost thereof, provided that the liens shall not extend to any principal property other than the property so acquired, constructed, developed or improved;

	•	liens in favor of the United States, any state or any foreign country or any department, agency or instrumentality or any political subdivision of the foregoing to secure payments pursuant to any contract or statute or to secure any indebtedness incurred for the purpose of financing all or any part of the purchase price or cost of constructing or improving the property subject to the lien, including liens related to governmental obligations the interest on which is tax-exempt under Section 103 of the Internal Revenue Code of 1986, as amended, or the Code, or any successor section of the Code;

	•	liens in favor of us, one or more of our significant subsidiaries, one or more of our wholly owned subsidiaries or any of the foregoing combination; and

	•	replacements, extensions or renewals (or successive replacements, extensions or renewals), in whole or in part, of any lien or of any agreement referred to in the bullet points above or replacements, extensions or renewals of the debt secured thereby (to the extent that the amount of the debt secured by the lien is not increased from the amount originally so secured, plus any premium, interest, fee or expenses payable in connection with any replacements, refundings, refinancings, remarketings, extensions or renewals); provided that replacement, extension or renewal is limited to all or a part of the same property (plus improvements thereon or additions or accessions thereto) that secured the lien replaced, extended or renewed.

Notwithstanding the restriction described above, we or a significant subsidiary may, from and after the release date, (i) issue, incur or assume debt secured by a lien not otherwise permitted under the immediately preceding six bullet points on any principal property owned at the date of execution of the indenture or thereafter acquired without providing that the outstanding senior bonds be equally and ratably secured with that debt and (ii) incur or permit to exist attributable debt in respect of principal property, in each case, so long as the aggregate amount of that debt and attributable debt, together with the aggregate amount of all other debt then outstanding secured by liens not described in the preceding six bullet points and all other attributable debt, does not exceed 10% of our net tangible assets, as determined by us as of a month end not more than 90 days prior to the closing or consummation of the proposed transaction.

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For these purposes:


	•	“attributable debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in the sale and leaseback transaction, including any period for which the lease has been extended or may, at the option of the lessor, be extended. The present value shall be calculated using a discount rate equal to the rate of interest implicit in the transaction, determined in accordance with GAAP.

	•	“capital lease obligations” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP.

	•	“debt” means any debt of ours for money borrowed and guarantees by us of debt for money borrowed but in each case not including liabilities in respect of capital lease obligations or swap agreements.

	•	“debt” of a significant subsidiary means any debt of such significant subsidiary for money borrowed and guarantees by the significant subsidiary of debt for money borrowed but in each case excluding liabilities in respect of capital lease obligations or swap agreements.

	•	“lien” means any mortgage, deed of trust, pledge, security interest, encumbrance, easement, lease, reservation, restriction, servitude, charge or similar right and any other lien of any kind, including, without limitation, any conditional sale or other title retention agreement, any lease of a similar nature, and any defect, irregularity, exception or limitation in record title or, when the context so requires, any lien, claim or interest arising from anything described in this bullet point.

	•	“net tangible assets” means the total amount of our assets determined on a consolidated basis in accordance with GAAP, less (i) the sum of our consolidated current liabilities determined in accordance with GAAP and (ii) the amount of our consolidated assets classified as intangible assets determined in accordance with GAAP, including, but not limited to, such items as goodwill, trademarks, trade names, patents and unamortized debt discount and expense and regulatory assets carried as an asset on our consolidated balance sheet.

	•	“principal property” means any property of ours or any of our significant subsidiaries, as applicable, other than property that prior to the release date would have constituted excepted property and property that were it to belong to us would have constituted excepted property prior to the release date.

	•	“significant subsidiary” has the meaning specified in Rule 1-02(w) of Regulation S-X under the Securities Act of 1933, as amended, or the Securities Act, provided that, significant subsidiary shall not include any corporation or other entity substantially all the assets of which are, or prior to the release date would have constituted, excepted property.

	•	“swap agreement” means any agreement with respect to any swap, forward, future or derivative transaction or option or similar agreement involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions.

Consolidation, Merger and Transfer of Mortgaged Property

We may not consolidate with or merge with or into any other person or convey, otherwise transfer or lease all or substantially all of our mortgaged property to any person unless:


	•	the person formed by that consolidation or into which we are merged or the person which acquires by conveyance or other transfer, or which leases, all or substantially all of the mortgaged property is a corporation, partnership, limited liability company, association, company, joint stock company or business trust, organized and existing under the laws of the United States, or any state thereof or the District of Columbia;

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	•	that person executes and delivers to the trustee a supplemental indenture that in the case of a consolidation, merger, conveyance or other transfer, or in the case of a lease if the term thereof extends beyond the last stated maturity of the senior bonds then outstanding, contains an assumption by the successor person of the due and punctual payment of the principal of and premium, if any, and interest, if any, on all senior bonds then outstanding and the performance and observance of every covenant and condition under the indenture to be performed or observed by us;

	•	in the case of a consolidation merger, conveyance or other transfer prior to the release date, that person executes and delivers to the trustee a supplemental indenture that contains a grant, conveyance, transfer and mortgage by the successor person confirming the lien of the indenture on the mortgaged property and subjecting to the lien of the indenture all property (other than excepted property) thereafter acquired by the successor person that shall constitute an improvement, extension or addition to the mortgaged property or renewal, replacement or substitution of or for any part thereof and, at the election of the successor person, subjecting to the lien of the indenture the other property, real, personal and mixed, then owned or thereafter acquired by the person as the person shall specify in its sole discretion;

	•	in the case of a lease, the lease is made expressly subject to termination by us or by the trustee at any time during the continuance of an event of default and by the purchaser of the property so leased at any sale of the property under the indenture, whether under the power of sale conferred by the indenture or pursuant to judicial proceedings;

	•	immediately after giving effect to the transaction and treating any indebtedness that becomes our obligation as a result of the transaction as having been incurred by us at the time of the transaction, no default or event of default shall have occurred and be continuing; and

	•	we have delivered to the trustee an officer’s certificate and an opinion of counsel, each stating that the merger, consolidation, conveyance, lease or transfer, as the case may be, fully complies with all provisions of the indenture; provided, however, that the delivery of the officer’s certificate and opinion of counsel shall not be required with respect to any merger, consolidation, conveyance, transfer or lease between us and any of our wholly owned subsidiaries.

Notwithstanding the foregoing, we may merge or consolidate with or transfer all or substantially all of our assets to an affiliate that has no significant assets or liabilities and was formed solely for the purpose of changing our jurisdiction of organization or our form of organization or for the purpose of forming a holding company; provided that the amount of our indebtedness is not increased; and provided, further that the successor assumes all of our obligations under the indenture.

In the case of the conveyance or other transfer of all or substantially all of the mortgaged property to any other person as contemplated under the indenture, upon the satisfaction of all the conditions described above, we (as we would exist without giving effect to the transaction) would be released and discharged from all obligations under the indenture and on the senior bonds then outstanding unless we elect to waive the release and discharge.

The meaning of the term “substantially all” has not been definitely established and is likely to be interpreted by reference to applicable state law if and at the time the issue arises and will depend on the facts and circumstances existing at the time.

For these purposes:


	•	“person” means any individual, corporation, limited liability partnership, joint venture, trust or unincorporated organization, or any other entity whether or not a legal entity, or any governmental authority.

From and after the release date, the term “mortgaged property” wherever used in this section, shall mean “principal property.”

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Modification of the Indenture; Waiver

We and the trustee may, with the consent of the holders of not less than a majority in aggregate principal amount of the senior bonds of each affected series then outstanding under the indenture, considered as one class, modify or amend the indenture, including the provisions relating to the rights of the holders of senior bonds of that series. However, no modification or amendment may, without the consent of each holder of affected senior bonds:


	•	change the stated maturity of the principal of, reduce the principal amount or any premium payable on, reduce the interest rate of, or change the method of calculating the interest rate with respect to that senior bond;

	•	reduce the amount of principal of any discount bond that would be payable upon acceleration of the maturity of that senior bond;

	•	change the type of consideration (coin, currency or other property) used to pay the principal of, or interest or premium on that senior bond;

	•	impair the right to institute suit for the enforcement of any payment on that senior bond;

	•	reduce the percentage in principal amount of outstanding senior bonds the consent of whose holders is required for modification or amendment of the indenture;

	•	reduce the percentage of principal amount of outstanding senior bonds necessary for waiver of compliance with certain provisions of the indenture or for waiver of defaults;

	•	modify the provisions with respect to modification and waiver, except as provided in the indenture;

	•	reduce the quorum or voting requirements applicable to holders of the senior bonds; or

	•	prior to the release date, permit the creation of any lien (not otherwise permitted by the indenture) ranking prior to the lien of the indenture, with respect to all or substantially all of the mortgaged property or, except as otherwise expressly permitted under the indenture, terminate the lien of the indenture on all or substantially all of the mortgaged property or deprive the holders of the senior bonds of the benefit of the lien of the indenture.

The holders of not less than a majority in aggregate principal amount of the senior bonds of each affected series then outstanding under the indenture, voting as a single class, may waive compliance by us with certain provisions of the indenture benefiting holders of senior bonds of that series or the applicable senior bonds. The holders of not less than a majority in aggregate principal amount of the senior bonds of any series outstanding under the indenture may, on behalf of the holders of all of the senior bonds of that series, waive any past default under the indenture with respect to that series and its consequences, except defaults in the payment of the principal of or any premium or interest on any senior bonds of that series and defaults in respect of a covenant or provision in the indenture which cannot be modified, amended or waived without the consent of each holder of affected senior bonds.

We and the trustee may, without the consent of any holder of senior bonds, amend the indenture and the senior bonds for certain reasons, including to:


	•	add covenants or other provisions applicable to us and for the benefit of the holders of senior bonds or one or more specified series thereof;

	•	cure ambiguities;

	•	correct or amplify the description of the mortgaged property, or to subject to the lien of the indenture additional property (including property of persons other than us);

	•	specify any additional permitted liens with respect to that additional property;

	•	add, change or eliminate any provision of the indenture so long as the addition, change or elimination does not adversely affect the interest of holders of senior bonds of any series in any material respect;

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	•	change any place or places for payment or surrender of senior bonds and where notices and demands to us may be served; and

	•	in connection with the occurrence of the release date, amend (including amending and restating) the indenture to eliminate any provisions related to liens (other than the provisions described above under “— Restrictions on Liens and Sale and Leaseback Transactions”), the lien of the indenture or the mortgaged property.

In order to determine whether the holders of the requisite principal amount of the outstanding senior bonds have taken an action under the indenture as of a specified date:


	•	the principal amount of a discount bond that will be deemed to be outstanding will be the amount of the principal that would be due and payable as of that date upon acceleration of the maturity to that date; and

	•	senior bonds owned by us or any other obligor upon the senior bonds or any of our or their affiliates will be disregarded and deemed not to be outstanding.

Events of Default

An “event of default” means any of the following events which shall occur and be continuing:


	•	failure to pay interest on a senior bond 30 days after such interest becomes due and payable;

	•	failure to pay the principal of, or premium, if any, on, a senior bond when due and payable;

	•	failure to perform or breach of any other covenant or warranty applicable to us in the indenture continuing for 90 days after the trustee gives us, or the holders of at least 33% in aggregate principal amount of the senior bonds then outstanding give us and the trustee, notice of the default or breach and requires us to remedy the default or breach, unless the trustee or the trustee and holders of a principal amount of senior bonds not less than the principal amount of senior bonds the holders of which gave that notice agree in writing to an extension of the period prior to its expiration;

	•	certain events of bankruptcy, insolvency or reorganization; and

	•	the occurrence of any event of default as defined in any mortgage, indenture or instrument under which there may be issued, or by which there may be secured or evidenced, any of our debt, whether the debt exists on the date of execution of the indenture or shall thereafter be created, if the event of default: (i) is caused by a failure to pay principal after final maturity of the debt after the expiration of the grace period provided in the debt (which we refer to as a “payment default”), or (ii) results in the acceleration of the debt prior to its express maturity, and in each case, the principal amount of any of that debt, together with the principal amount of any other debt under which there has been a payment default or the maturity of which has been so accelerated, aggregates $100 million or more, provided, however, that if prior to the release date, the event of default under that mortgage, indenture or instrument is cured or waived or the acceleration is rescinded or the debt is repaid, within a period of 20 days from the continuation of that event of default beyond the applicable grace period or the occurrence of the acceleration, as the case may be, the event of default described in this bullet point shall be automatically cured; provided, further, that with respect to any mortgage, indenture or instrument that exists on the date of execution of the indenture, this provision only applies to the extent that the obligations to pay amounts thereunder are enforceable after the effective date of our plan of reorganization.

The $100 million amount specified in the bullet point above shall be increased in any calendar year subsequent to 2004 by the same percentage increase in the urban CPI for the period commencing January 1, 2004 and ending on January 1 of the applicable calendar year.

If the trustee deems it to be in the interest of the holders of the senior bonds, it may withhold notice of default, except defaults in the payment of principal of or interest or premium on or with respect to, any senior bond.

If an event of default occurs and is continuing, the trustee or the holders of a majority in aggregate principal amount prior to the release date, or 33% in aggregate principal amount on and after the release date, of the senior

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bonds outstanding, considered as one class, may declare all principal immediately due and payable; provided, however, that if an event of default occurs with respect to certain events of bankruptcy, insolvency or reorganization, then the senior bonds outstanding shall be due and payable immediately without further action by the trustee or holders. If the default has been cured and other specified conditions in the indenture have been satisfied before any mortgaged property has been sold and before a judgment or decree for payment has been obtained by the trustee as provided in the indenture, the event or events of default giving rise the acceleration will be deemed to have been cured and the declaration of acceleration and its effect will be deemed to have been rescinded and annulled.

No holder of senior bonds will have any right to enforce any remedy under the indenture unless the holder has given the trustee written notice of the event of default, the holders of at least 33% in aggregate principal amount of the senior bonds have requested the trustee in writing to institute proceedings with respect to the event of default in its own name as trustee under the indenture and have offered the trustee reasonable indemnity against costs, expenses and liabilities with respect to the request, the trustee has failed to institute any proceeding within 60 days after receiving the notice from holders, and no direction inconsistent with the written request has been given to the trustee during the 60-day period by holders of at least a majority in aggregate principal amount of senior bonds then outstanding.

The trustee is not required to risk its funds or to incur financial liability if there is a reasonable ground for believing that repayment to it or adequate indemnity against risk or liability is not reasonably assured.

If an event of default has occurred and is continuing, holders of a majority in principal amount of the senior bonds may establish the time, method and place of conducting any proceedings for any remedy available to the trustee, or exercising any trust or power conferred upon the trustee.

Discharge

Any senior bond, or any portion of the principal amount thereof, will be deemed to have been paid for purposes of the indenture and, at our election, our entire indebtedness in respect of the senior bonds will be deemed to have been satisfied and discharged, if certain conditions are satisfied, including an irrevocable deposit with the trustee or any paying agent (other than us) in trust of:


	•	money (including funded cash not otherwise applied pursuant to the indenture) in an amount which will be sufficient; or

	•	in the case of a deposit made prior to the maturity of the senior bonds or portions thereof, eligible obligations (as described below) which do not contain provisions permitting the redemption or other prepayment thereof at the option of the issuer thereof, the principal of and the interest on which when due, without any regard to reinvestment thereof, will provide monies which, together with the money, if any, deposited with or held by the trustee or the paying agent, will be sufficient; or

	•	a combination of either of the two items described in the two preceding bullet points which will be sufficient;

to pay when due the principal of and premium, if any, and interest, if any, due and to become due on the senior bonds or portions thereof.

For this purpose, “eligible obligations” include direct obligations of, or obligations unconditionally guaranteed by, the United States of America, entitled to the benefit of the full faith and credit thereof, and depositary receipts or other instruments with respect to the obligations or any specific interest or principal payments due in respect thereof.

Book-Entry System; Global Bonds

Except as set forth below, the mortgage bonds will initially be issued in the form of one or more global bonds for each series. Each global bond will be deposited with DTC or the trustee on behalf of DTC on the date of the closing and will be registered in the name of DTC or its nominee. Investors may hold their beneficial interests in a global bond directly through DTC or indirectly through organizations which are participants in the DTC system.

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Unless and until they are exchanged in whole or in part for certificated bonds, the global bonds may not be transferred except as a whole by DTC or its nominee.

DTC has advised us as follows:


	•	DTC is a limited purpose trust company organized under the laws of the State of New York, a “banking organization” within the meaning of the New York Banking Law, a member of the Federal Reserve System, a “clearing corporation” within the meaning of the Uniform Commercial Code and a “clearing agency” registered under the provisions of Section 17A of the Securities Exchange Act of 1934.

	•	DTC holds securities that its direct participants deposit with it. DTC also facilitates the post-trade settlement among direct participants of sales and other securities transactions in deposited securities through electronic book-entry transfers and pledges between direct participants’ accounts. This eliminates the need for physical movement of securities certificates. Direct participants include both U.S. and non-U.S. securities brokers and dealers, banks, trust companies, clearing corporations and certain other organizations. DTC is a wholly owned subsidiary of The Depository Trust & Clearing Corporation, or DTCC. DTCC, in turn, is owned by a number of DTC’s direct participants, all of which are members of the National Securities Clearing Corporation, Government Securities Clearing Corporation, MBS Clearing Corporation, and Emerging Markets Clearing Corporation, also subsidiaries of DTCC, and by the New York Stock Exchange, Inc., the American Stock Exchange LLC and the National Association of Securities Dealers, Inc. Access to the DTC system is available to others, including both U.S. and non-U.S. securities brokers and dealers, banks, trust companies and clearing corporations that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly. DTC has S&P’s highest rating: AAA. The DTC rules applicable to its direct and indirect participants are on file with the SEC. More information about DTC can be found at www.dtcc.com.

	•	Purchases of the mortgage bonds under the DTC system must be made by or through direct participants, which will receive a credit for the mortgage bonds on DTC’s records. The ownership interest of each actual purchaser of each mortgage bond, or the beneficial owner, is, in turn, to be recorded on the direct and indirect participants’ record. Beneficial owners will not receive written confirmation from DTC of their purchase. Beneficial owners are, however, expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the direct or indirect participant through which the beneficial owner entered into the transaction. Transfers of ownership interests in the mortgage bonds are to be accomplished by entries made on the books of direct and indirect participants acting on behalf of beneficial owners. Beneficial owners will not receive certificates representing their ownership interests in mortgage bonds except in the event that use of the book-entry system for the mortgage bonds is discontinued.

	•	To facilitate subsequent transfers, all mortgage bonds deposited by direct participants with DTC are registered in the name of DTC’s partnership nominee, Cede & Co., or such other name as may be requested by an authorized representative of DTC. The deposit of mortgage bonds with DTC and their registration in the name of Cede & Co. or such other DTC nominee do not effect any change in beneficial ownership. DTC has no knowledge of the actual beneficial owners of the mortgage bonds; DTC’s records reflect only the identity of the direct participants to whose accounts the mortgage bonds are credited, which may or may not be the beneficial owners. The direct and indirect participants will remain responsible for keeping account of their holdings on behalf of their customers.

	•	Conveyance of notices and other communications by DTC to direct participants, by direct participants to indirect participants, and by direct participants and indirect participants to beneficial owners will be governed by arrangements among them, subject to any statutory or regulatory requirements as may be in effect from time to time. Beneficial owners of the mortgage bonds may wish to take certain steps to augment the transmission to them of notices of significant events with respect to the mortgage bonds, such as redemptions, tenders, defaults and proposed amendments to the mortgage bond documents. For example, beneficial owners of mortgage bonds may wish to ascertain whether the nominee holding the mortgage bonds for their benefit has agreed to obtain and transmit notices to beneficial owners. In the

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		alternative, beneficial owners may wish to provide their names and addresses to the registrar and request that copies of notices be provided directly to them.

	•	Redemption notices shall be sent to DTC. If less than all of the mortgage bonds within a series are being redeemed, DTC’s practice is to determine by lot the amount of the interest of each direct participant in the series to be redeemed.

	•	Neither DTC nor Cede & Co. (nor any other DTC nominee) will consent or vote with respect to mortgage bonds unless authorized by a direct participant in accordance with DTC’s procedures. Under its usual procedures, DTC mails an omnibus proxy to the issuer as soon as possible after the record date. The omnibus proxy assigns Cede & Co.’s consenting or voting rights to those direct participants to whose accounts mortgage bonds are credited on the record date (identified in a listing attached to the omnibus proxy).

	•	Redemption proceeds, distributions and dividend payments on the mortgage bonds will be made to Cede & Co. or such other nominee as may be requested by an authorized representative of DTC. DTC’s practice is to credit direct participants’ accounts upon DTC’s receipt of funds and corresponding detail information from the issuer or the agent, on payable date in accordance with their respective holdings shown on DTC’s records. Payments by participants to beneficial owners will be governed by standing instructions and customary practices, as is the case with securities held for the accounts of customers in bearer form or registered in “street name,” and will be the responsibility of the participant and not of DTC nor its nominee, agent or the issuer, subject to any statutory or regulatory requirements as may be in effect from time to time. Payment of redemption proceeds, distributions and dividend payments to Cede & Co. (or such other nominee as may be requested by an authorized representative of DTC) is the responsibility of the issuer or agent, disbursement of the payments to direct participants will be the responsibility of DTC, and disbursement of such payments to the beneficial owners will be the responsibility of direct and indirect participants.

	•	A beneficial owner shall give notice to elect to have its mortgage bond purchased or tendered, through its participant, to the agent, and shall effect delivery of the mortgage bond by causing the direct participant to transfer the participant’s interest in the mortgage bond, on DTC’s records, to the agent. The requirement for physical delivery of the mortgage bond in connection with an optional tender or a mandatory purchase will be deemed satisfied when the ownership rights in the mortgage bond are transferred by direct participants on DTC’s records and followed by a book-entry credit of the tendered mortgage bond to the agent’s DTC account.

	•	DTC may discontinue providing its services as depositary with respect to the mortgage bonds at any time by giving reasonable notice to the issuer or the agent. Under such circumstances, in the event that a successor depositary is not selected, mortgage bond certificates are required to be printed and delivered.

The issuer may decide to discontinue use of the system of book-entry transfers through DTC (or a successor securities depositary). In that event, mortgage bond certificates will be printed and delivered.

The information in this section concerning DTC and DTC’s book-entry system has been obtained from sources that the issuer believes to be reliable but the issuer takes no responsibility for the accuracy thereof.

Second Supplemental Indenture

On the effective date of our plan of reorganization, we will enter into a second supplemental indenture with the trustee and will issue senior bonds to the administrative agents and a bond insurer in connection with certain of the credit facilities and other arrangements described under “— Description of Other Indebtedness” to provide security for these obligations. These senior bonds will be issued in a total maximum aggregate principal amount of approximately $2.5 billion. Each series of these senior bonds will be issued in an aggregate principal amount equal to the obligations they secure. These senior bonds will rank pari passu with the mortgage bonds offered by this prospectus supplement and the accompanying prospectus. The actual principal amount of any of these senior bonds that will be outstanding at any time will vary from time to time as the amounts of our obligations with respect to the related credit facility or other arrangement vary.

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DESCRIPTION OF OTHER INDEBTEDNESS

At the effective date of our plan of reorganization, we will reinstate certain of our existing debt. PG&E Funding LLC, a limited liability company that we wholly own, also will continue to be obligated under certain rate reduction bonds. In addition, we have entered into several credit facilities and PG&E Accounts Receivable Company LLC, a limited liability company that we wholly own, has entered into an accounts receivable facility.

Revolving Credit Facility

General

We have entered into a three-year $850 million revolving credit facility, or the working capital facility.

Use of Proceeds

Loans under the working capital facility will be used primarily to cover operating expenses and seasonal fluctuations in working capital and may be used to pay allowed claims on the effective date of our plan of reorganization. Letters of credit issued under the working capital facility will be used to provide credit enhancement to counterparties for natural gas and electricity procurement transactions and may be used for any other general corporate purpose.

Term

Unless extended, the working capital facility will terminate and all outstanding amounts will be due and payable in full on March 5, 2007. The facility may, at our request and in the sole discretion of each lender, be extended for additional periods.

Funding on the Effective Date

There will be no extension of credit under the working capital facility until the effective date of our plan of reorganization. Extension of credit under this facility on the effective date is subject to the satisfaction or waiver of certain conditions, including:


	•	the satisfaction or, under specified circumstances, waiver of all the conditions to the effectiveness of our plan of reorganization other than any conditions related to the closing of the debt financings and other credit facilities contemplated by our plan of reorganization;

	•	the funding or release from escrow of proceeds of the other financings contemplated by our plan of reorganization to be made available on the effective date of our plan of reorganization;

	•	the absence of any amendments to our plan of reorganization or the confirmation order that could be reasonably expected to materially and adversely affect our ability to perform our obligations under the working capital facility; and

	•	the issuance and delivery of a senior bond under the indenture to secure the working capital facility.

Non-Funding Termination Date

If our plan of reorganization does not become effective on or before the earlier of the 90th day after the closing of the sale of the mortgage bonds or September 1, 2004, the working capital facility will automatically terminate unless, before the termination date, we and each of the lenders have agreed in writing to extend the termination date.

Security

Our obligations under the working capital facility will be secured by senior bonds issued by us in an aggregate principal amount equal to the total amount of the working capital facility. These senior bonds will rank pari passu with the mortgage bonds. However, we have agreed not to release the lien of the indenture unless the ratings on our unsecured long-term debt are at least Baa2 from Moody’s and BBB from S&P.

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Covenants

The working capital facility includes customary covenants, including covenants related to:


	•	maintenance, as of the end of each fiscal quarter ending after the effective date of our plan of reorganization, of a debt to capitalization ratio of at least 0.65 to 1.00;

	•	no dispositions of assets, other than dispositions of inventory and obsolete property in the ordinary course, in excess of 25% of the aggregate book value of our and our significant subsidiaries’ assets at December 31, 2003;

	•	maintenance of our corporate existence and compliance with laws;

	•	payment of taxes;

	•	maintenance of insurance;

	•	a limitation on liens no more restrictive than the limitation on liens that becomes effective under the indenture from and after the release date;

	•	limitation on mergers and sales of all or substantially all of our assets; and

	•	maintenance of any governmental authorization or approval necessary in connection with the operation of our business.

Events of Default

The working capital facility includes customary events of default, including:


	•	nonpayment of principal, interest, fees or other amounts;

	•	breach of covenants;

	•	inaccuracy of representations and warranties;

	•	cross-default to other debt in excess of $75 million;

	•	bankruptcy and other insolvency events;

	•	unpaid or unstayed judgments in excess of $75 million;

	•	invalidity of any loan documentation or, prior to the release date, the lien of the indenture;

	•	the staying, reversal, vacating or modifying, on or after the effective date of our plan of reorganization, of the bankruptcy court’s order confirming our plan of reorganization in any material manner that could reasonably be expected to materially and adversely affect our ability to perform our obligations under the working capital facility; and

	•	a change of control arising from Corp owning less than a specified percentage of our capital stock.

As discussed above under “Description of the First Mortgage Bonds — Events of Default,” the indenture contains an event of default related to the acceleration of any debt in excess of $100 million, plus increases in the urban CPI subsequent to calendar year 2004. This amount is higher than the $75 million threshold that applies to a cross-default under the working capital facility, as described above.

Accounts Receivable Financing


	*General*

We have entered into certain agreements providing for the sale of accounts receivable to PG&E Accounts Receivable Company LLC, our wholly-owned, special purpose subsidiary. PG&E Accounts Receivable Company LLC, in turn, will sell interests in the accounts receivable to commercial paper conduits or banks. We will continue to service the accounts receivable, but will have no right to the cash collected from those

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receivables, other than for payment of our servicing fee. PG&E Accounts Receivable Company LLC may obtain up to $650 million in financing under these agreements.

While PG&E Accounts Receivable Company LLC is our wholly-owned subsidiary, it is legally separate from us. Its assets are not available to our creditors, and the receivables that are sold to PG&E Accounts Receivable Company LLC will no longer legally be our assets.


	*Use of Proceeds*

Proceeds from the sale of the accounts receivable will be used to pay allowed claims on the effective date of our plan of reorganization. Proceeds will also be used to cover operating expenses and seasonal fluctuations in working capital.


	*Term*

Unless extended, the accounts receivable facility will terminate on March 5, 2007. The facility may be extended for additional periods upon the agreement of all parties.


	*Funding on the Effective Date*

No accounts receivable will be sold until the effective date of our plan of reorganization. The purchase of accounts receivable under this facility on the effective date is subject to the satisfaction or waiver of certain conditions, including:


	•	the satisfaction or, under specified circumstances, waiver of all the conditions to the effectiveness of our plan of reorganization other than any conditions related to the closing of the debt financings and other financings contemplated by our plan of reorganization;

	•	the funding or release from escrow of proceeds of the other financings contemplated by our plan of reorganization to be made available on the effective date of our plan of reorganization; and

	•	the absence of any amendments to our plan of reorganization or the confirmation order that could be reasonably expected to materially and adversely affect our ability to perform our obligations under the accounts receivable facility or the rights of the purchasers under the facility.


	*Non-Funding Termination Date*

If our plan of reorganization does not become effective on or before the earlier of the 90th day after the closing of the sale of the mortgage bonds or September 1, 2004, the accounts receivable facility will automatically terminate unless, before the termination date, we, PG&E Accounts Receivable Company LLC and each of the purchasers agree in writing to extend the termination date.


	*Covenants*

The accounts receivable facility includes customary covenants on our part and on the part of PG&E Accounts Receivable Company LLC, including covenants related to:


	•	maintenance of corporate existence and compliance with laws;

	•	servicing of the receivables in accordance with our credit and collection policy;

	•	protecting the interests of the purchasers in the accounts receivable;

	•	payment of taxes;

	•	maintenance of any governmental authorization or approval necessary in connection with the operation of our business; and

	•	indemnification of the purchasers.

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	*Amortization Events*

The purchasers will cease purchasing receivables, and all amounts payable under the accounts receivable facility will become due and payable, upon the occurrence of certain amortization events, including:


	•	a failure to deposit or pay amounts due under the facility;

	•	breach of covenants;

	•	inaccuracy of representations and warranties;

	•	default on indebtedness in excess of $75 million;

	•	bankruptcy and other insolvency events;

	•	a deterioration in the credit quality of the receivables below certain specified thresholds;

	•	a change of control arising from Corp owning less than a specified percentage of our capital stock;

	•	unpaid or unstayed judgments in excess of $75 million;

	•	invalidity of any accounts receivable purchase agreements or the failure of the purchasers to have a valid and perfected first priority security interest in the receivables; and

	•	the staying, reversal, vacating or modifying, on or after the effective date of our plan of reorganization, of the bankruptcy court’s order confirming our plan of reorganization in any material manner that could reasonably be expected to materially and adversely affect our ability to perform our obligations under the accounts receivable facility.

Cash Collateralized Letter of Credit Facility

We have entered into a cash collateralized $400 million letter of credit facility that, prior to the effective date of our plan or reorganization, may be used to issue letters of credit to provide credit support in connection with our natural gas procurement activities and related purchases of natural gas transportation services. After the effective date of our plan of reorganization, this facility may be used to issue letters of credit for any general corporate purpose, subject to our satisfaction of certain conditions.

Pollution Control Bonds

We have various loan agreements with the California Pollution Control Financing Authority, or CPCFA, that we will reinstate at the effective date of our plan of reorganization. Under these loan agreements, we are required to repay loans made to us by the CPCFA at the times and in the amounts necessary to enable the CPCFA to make a full and timely payment of the principal of, premium, if any, and interest on certain series of pollution control bonds issued by the CPCFA for our benefit, the proceeds from the initial sale of which pollution control bonds were loaned to us under the terms of the loan agreements. The CPCFA has assigned its right to receive the loan payments under each of the loan agreements to a trustee for the benefit of the holders of the respective series of pollution control bonds under the terms of the various indentures of trust pursuant to which the pollution control bonds were issued.

Four series of pollution control bonds, totaling approximately $614 million in aggregate principal amount, are currently supported by letters of credit issued by various banks for our account. One series of pollution control bonds, totaling $200 million in aggregate principal amount, is supported by a bond insurance policy. The related loan agreements with the CPCFA provide that to the extent payments of principal, premium or interest on a series of pollution control bonds is made through a draw on the letter of credit or bond insurance policy supporting that series of pollution control bonds, we will be deemed to have satisfied our obligation to the CPCFA to make corresponding payments under the related loan agreement to the extent of the payment under the letter of credit or bond insurance policy.

At the effective date of our plan of reorganization, we will replace the existing letters of credit with approximately $620 million of new letters of credit under a new pollution control bond letter of credit facility.

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The term, funding procedures, non-funding termination date, covenants and events of default under the pollution control bond letter of credit facility are substantially identical to those of the working capital facility.

Under reimbursement agreements we have entered into with the new letter of credit banks and the existing agreement with the bond insurer, which will be amended and restated on the effective date of our plan of reorganization, we are obligated to reimburse the letter of credit banks and the bond insurer for draws made on the letters of credit and payments made under the bond insurance policy, including interest on unreimbursed amounts. As with the working capital facility, until the release date, our obligations under each of the pollution control bond letter of credit facility and our reimbursement agreements with the bond insurer will be secured by senior bonds issued by us under the indenture in an aggregate principal amount equal to the total amount of the pollution control bond letter of credit facility or the bond insurance. These senior bonds will rank pari passu with the mortgage bonds.

The four series of pollution control bonds with approximately $614 million in aggregate principal amount have variable interest rates and mature in 2026. For 2003, the variable interest rates ranged from 0.75% to 1.31%. These series are subject to redemption under certain circumstances. The letters of credit supporting these series are discussed above. The remaining series, with a $200 million aggregate principal amount, bears a 5.35% interest rate and matures in 2016. This series is supported by bond insurance.

In connection with our plan of reorganization, we also expect to either repurchase or redeem approximately $345 million in aggregate principal amount of currently outstanding pollution control bonds. During the course of our bankruptcy proceedings, approximately $454 million in aggregate principal amount of pollution control bonds, which had been issued for our benefit, were redeemed through draws made on letters of credit, giving rise to an obligation to reimburse the issuers of these letters of credit for the amounts drawn. In connection with our plan of reorganization, we expect to either satisfy this reimbursement obligation, or to cause certain financial institutions to purchase this reimbursement obligation for a purchase price equal to the amount of such reimbursement obligation. If we elect to arrange for financial institutions to purchase this reimbursement obligation, we expect to enter into agreements with these financial institutions to allow us to repay this reimbursement obligation over time though the issuance of new refunding pollution control bonds or otherwise. To fund these purchases, we have entered into a 15-month $345 million term loan facility and a 15-month $454 million reimbursement facility. Each of these facilities may, at our request, and in the sole discretion of the lenders under the applicable credit facility be extended for additional periods. The funding procedures, non-funding termination date, covenants and event of default under these facilities are substantially identical to those of the working capital facility and pollution control bond letter of credit facility. Each of these facilities also will be secured by senior bonds issued by us under the indenture in an aggregate principal amount equal to the amount of each facility. These senior bonds will rank pari passu with the mortgage bonds.

Rate Reduction Bonds

In December 1997, PG&E Funding LLC issued $2.9 billion of rate reduction bonds to the California Infrastructure and Economic Development Bank Special Purpose Trust. The terms of the bonds generally mirror the terms of pass-through certificates issued by the trust. The proceeds of the rate reduction bonds were used by PG&E Funding LLC to purchase from us the right known as “transition property,” to be paid a specified amount from a non-bypassable charge levied on our residential and small commercial customers. The bonds are secured only by the transition property, and there is no recourse to us.

At December 31, 2003, approximately $1.16 billion of rate reduction bonds were outstanding bearing interest at rates of 6.42% to 6.48%. Each year, $290 million in principal is paid. The bonds’ final maturity is 2007. While PG&E Funding LLC is our wholly owned subsidiary, it is legally separate from us. Its assets are not available to our creditors, and the transition property is not legally our asset.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

The following summary describes certain material United States federal income tax consequences of the purchase, ownership and disposition of the mortgage bonds as of the date of this prospectus supplement. Except where noted, this summary deals only with the mortgage bonds acquired in the offering at the initial offering price and held as capital assets within the meaning of Section 1221 of the Code and does not deal with specific situations, such as those of dealers in securities or currencies, financial institutions, tax-exempt organizations, life insurance companies, real estate investment companies, regulated investment companies, persons holding the mortgage bonds as part of a hedging or conversion transaction or a straddle, persons deemed to sell mortgage bonds under the constructive sale provisions of the Code or persons whose functional currency is not the United States dollar or who have any other special tax status with respect to the United States. Furthermore, the discussion below is based upon the existing provisions of the Code, existing and proposed United States Treasury regulations, and current Internal Revenue Service, or IRS, rulings and judicial decisions implementing or construing the Code, all of which are subject to change, possibly on a retroactive basis, which could result in United States federal income tax consequences different from those discussed below.

Prospective purchasers of the mortgage bonds, including persons who purchase the mortgage bonds in the secondary market, are advised to consult with their tax advisors as to the United States federal income tax consequences of the purchase, ownership and disposition of the mortgage bonds in light of their particular circumstances, as well as the effect of any state, local or other tax laws.

United States Holders

As used in this prospectus supplement, “United States holder” means a beneficial owner of a mortgage bond that is:


	•	a citizen or resident of the United States for United States federal income tax purposes;

	•	a corporation (or any entity treated as a corporation for United States federal income tax purposes) created or organized under the laws of the United States, any state or the District of Columbia;

	•	an estate the income of which is subject to United States federal income tax without regard to its source; or

	•	a trust if it:


	•	is subject to the primary jurisdiction of a court within the United States and one or more United States persons have the authority to control all substantial decisions of the trust; or

	•	was a United States person prior to August 19, 1996 and has a valid election in effect under applicable United States Treasury regulations to continue to be treated as a United States person.

If a partnership (including any entity treated as a partnership for United States federal income tax purposes) is a holder of a mortgage bond, the United States federal income tax treatment of a partner in that partnership will generally depend on the status of the partner and the activities of the partnership. Partners should consult their own tax advisors as to the particular federal income tax consequences applicable to them.

A “non-United States holder” is any beneficial owner of a mortgage bond (other than a partnership) that is not a United States holder.

Tax Consequences to United States Holders

We do not believe that the mortgage bond will be issued with more than a de minimis amount of original issue discount, if any. Interest on a mortgage bond will therefore generally be taxable to a United States holder as ordinary income as it accrues or is received in accordance with the United States holder’s method of accounting for United States federal income tax purposes.

Upon the sale, exchange, redemption, retirement or other disposition of a mortgage bond, a United States holder generally will recognize gain or loss equal to the difference between the amount realized upon the sale,

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exchange, redemption, retirement or other disposition (not including amounts attributable to accrued interest not previously included in income, which will be taxable as ordinary interest income) and the United States holder’s adjusted tax basis in the mortgage bond. A United States holder’s adjusted tax basis in a mortgage bond will, in general, be the United States holder’s cost, less any principal payments the holder received. The gain or loss generally will be capital gain or loss, and will be long-term capital gain or loss if at the time of sale, exchange or retirement the mortgage bond has been held for more than one year. Individuals are eligible for reduced rates of taxation on long-term capital gains. The deductibility of capital losses is subject to limitations.

Tax Consequences to Non-United States Holders

Under present United States federal income tax law, subject to the discussion of backup withholding and information reporting below:


	•	a non-United States holder will not be subject to United States federal income, branch profits or withholding tax on payments of interest on a mortgage bond provided that:


	•	the non-United States holder does not actually or constructively own 10% or more of the total combined voting power of all classes of our stock entitled to vote;

	•	the non-United States holder is not a bank receiving interest from us on an extension of credit pursuant to a loan agreement entered into in the ordinary course of its trade or business;

	•	the non-United States holder is not a controlled foreign corporation that is related to us (directly or indirectly) through stock ownership;

	•	the interest payments are not effectively connected with the conduct of a United States trade or business; and

	•	certain certification requirements are met; and


	•	a non-United States holder will not be subject to United States federal income or branch profits tax on gain realized on the sale, exchange, redemption, or retirement or other disposition of a mortgage bond, unless:


	•	the gain is effectively connected with the conduct of a United States trade or business or, if a treaty applies (and the holder complies with applicable certification and other requirements to claim treaty benefits), is generally attributable to a United States permanent establishment maintained by the holder;

	•	the holder is an individual who is present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met; or

	•	the holder is subject to tax pursuant to the provisions of the United States federal income tax law applicable to certain expatriates.

The certification requirements described above will be satisfied if the beneficial owner of the mortgage bond certifies on IRS Form W-8BEN or a substantially similar substitute form, under penalties of perjury, that it is not a United States person and provides its name and address, and the beneficial owner files the form with the withholding agent or, in the case of a mortgage bond held through a foreign partnership or intermediary, the beneficial owner and the foreign partnership or intermediary satisfy certification requirements of applicable United States Treasury regulations.

If a non-United States holder does not qualify for the exemption of interest income on a mortgage bond described above, payments of premium, if any, and interest made to such non-United States holder will be subject to a 30% withholding tax unless the beneficial owner of the mortgage bond provides a properly executed (i) IRS Form W-8BEN claiming an exemption from or reduction in withholding under the provisions of an applicable income tax treaty or (ii) IRS Form W-8ECI stating that interest paid on the mortgage bond is not subject to withholding tax because it is effectively connected with the beneficial owner’s conduct of a trade or business in the United States. Alternative documentation may be applicable in certain situations.

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If premium or interest on a mortgage bond is effectively connected with the conduct of a United States trade or business, the non-United States holder generally will be subject to United States federal income tax on such premium or interest on a net income basis in the same manner as if it were a United States holder (and, if such holder is a corporation, it also may be subject to a 30% branch profits tax). If premium or interest on a mortgage bond is subject to United States federal income tax on a net income basis in accordance with these rules, such payments will not be subject to the United States withholding tax discussed above if the non-United States holder satisfies the certification requirements described above.

A mortgage bond held by an individual who at the time of death is not a citizen or resident of the United States will not be subject to United States federal estate tax with respect to a mortgage bond as a result of the individual’s death, provided that:


	•	the individual does not actually or constructively own 10% or more of the total combined voting power of all classes of our stock entitled to vote; and

	•	the interest accrued on the mortgage bond was not effectively connected with the conduct of a United States trade or business.

Special rules may apply to certain non-United States holders, such as “controlled foreign corporations,” “passive foreign investment companies,” “foreign personal holding companies,” foreign tax-exempt organizations, foreign private foundations and certain expatriates, that are subject to special treatment under the Code. Such entities should consult their own tax advisors to determine the United States federal, state, local and other tax consequences that may be relevant to them.

Redemption of First Mortgage Bonds

The mortgage bonds will be redeemed in the event that our plan of reorganization does not become effective within a certain period of time. See “Use of Proceeds.” We do not believe that this feature will cause the mortgage bonds to be subject to special rules applicable to contingent payment debt obligations. However, in the event that those special rules were applicable, holders of mortgage bonds would generally be required to accrue interest on a current basis and to treat any gain recognized on a disposition of the mortgage bonds as ordinary income.

Discharge of the First Mortgage Bonds

Under certain circumstances, we may discharge the mortgage bonds of a particular series. See “Description of the First Mortgage Bonds — Discharge” and “ — Discharge of Lien; Release Date.” Discharge may be treated as a taxable disposition by the holders of those mortgage bonds. Prospective investors in the mortgage bonds should consult their own tax advisors as to the particular federal income tax consequences applicable to them in the event of such discharge.

Backup Withholding and Information Reporting

In general, payments of interest and the proceeds of the sale, exchange, redemption, retirement or other disposition of a mortgage bond payable by a United States paying agent or other United States intermediary will be subject to information reporting. In addition, backup withholding at the then applicable rate (currently 28%) will generally apply to these payments if:


	•	in the case of a United States holder, the holder fails to provide an accurate taxpayer identification number, fails to certify that the holder is not subject to backup withholding or fails to report all interest and dividends required to be shown on its United States federal income tax returns; or

	•	in the case of a non-United States holder, the holder fails to provide the certification on IRS Form W-8BEN described above or otherwise does not provide evidence of exempt status.

Certain United States holders (including, among others, corporations) and non-United States holders that comply with certain certification requirements are not subject to backup withholding. Any amount paid as backup withholding will be creditable against the holder’s United States federal income tax liability and may entitle the

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holder to a refund, provided that the required information is timely furnished to the IRS. Furthermore, certain penalties may be imposed on a holder of a mortgage bond who fails to provide the IRS with information in the proper form. Holders of the mortgage bonds should consult their tax advisors as to their qualification for exemption from backup withholding and the procedure for obtaining an exemption.

RATINGS

The mortgage bonds are expected to be rated by Moody’s and BBB by S&P. Definitive debt ratings will not be assigned until the effective date of our plan of reorganization. These ratings reflect only the views of these organizations. An explanation of the significance of each such rating may be obtained from Moody’s Investors Service, 99 Church Street, New York, New York 10007 and Standard & Poor’s Ratings Services, 55 Water Street, New York, New York 10004. There is no assurance that these ratings will actually be assigned, that they will continue for any given period of time or that they will not be revised downward or withdrawn entirely by the rating agencies or either of them if, in their judgment, circumstances so warrant. A failure to obtain, downward change in or withdrawal of these ratings by either of the rating agencies may have an adverse effect on the market price of the mortgage bonds. A security rating is not a recommendation to buy, sell or hold securities, and each rating should be evaluated independently of any other rating.

UNDERWRITING

Each of the underwriters named below has severally agreed to purchase from us the principal amount of the mortgage bonds set forth opposite its name.

Principal

Total

Principal

Amount of

Principal

Amount of

Floating

Amount of

% First

Rate First

First

Mortgage

Underwriters

Bonds due

Bonds

Lehman Brothers Inc.

UBS Securities LLC

Citigroup Global Markets Inc.

Banc One Capital Markets, Inc.

Credit Suisse First Boston LLC

ABN AMRO Incorporated

Barclays Capital Inc.

BNP Paribas Securities Corp.

Deutsche Bank Securities Inc.

BNY Capital Markets, Inc.

Blaylock & Partners, L.P.

Siebert Brandford Shank & Co., LLC

Total

The underwriters will purchase the mortgage bonds pursuant to an underwriting agreement with us. The underwriters will pay us the public offering price and we will pay them the underwriting commissions specified on the cover page to this prospectus supplement. We estimate our expenses for this offering to be approximately $ . Certain conditions contained in the underwriting agreement must be satisfied before the underwriters are required to purchase the mortgage bonds. The underwriters will either purchase all of the mortgage bonds or none of them.

The underwriters have advised us that they will offer the mortgage bonds directly to the public initially at the public offering prices specified on the cover page to this prospectus supplement and may also offer the mortgage bonds to certain dealers at the public offering prices less a selling concession not to exceed % of the

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principal amount of the % first mortgage bonds due , % of the principal amount of the % first mortgage bonds due , % of the principal amount of the % first mortgage bonds due , % of the principal amount of the % first mortgage bonds due and % of the principal amount of the floating rate first mortgage bonds due . The underwriters may allow and these dealers may reallow a concession not to exceed % of the principal amount of the mortgage bonds to other dealers. After the initial offering of the mortgage bonds, the underwriters may change the public offering prices, the concession to selected dealers and the reallowance to other dealers.

The underwriters will offer the mortgage bonds subject to prior sale, withdrawal, cancellation or modification of the offer of the mortgage bonds without notice, and to their receipt and acceptance of the mortgage bonds. The underwriters may reject any order to purchase the mortgage bonds.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, or to contribute to payments which the underwriters may be required to make in respect thereof.

There is currently no public market for the mortgage bonds, and we currently have no intention to list the mortgage bonds on any securities exchange or automated quotation system. The underwriters have advised us that they currently intend to make a market in the mortgage bonds as permitted by applicable laws and regulations. The underwriters are not obligated to make a market in the mortgage bonds, however, and they may discontinue such market making at any time in their sole discretion. Accordingly, there may not be adequate liquidity or adequate trading markets for the mortgage bonds.

In connection with this offering, Lehman Brothers Inc. and UBS Securities LLC, on behalf of the other underwriters, may purchase and sell the mortgage bonds in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater total principal amount of the mortgage bonds than they are required to purchase in this offering. Stabilizing transactions consist of certain bids or purchases made for the purpose of preventing or retarding a decline in the market price of the mortgage bonds while this offering is in progress.

Lehman Brothers Inc. and UBS Securities LLC, on behalf of the other underwriters, also may impose a penalty bid. This may occur when a particular underwriter repays to the underwriters a portion of the underwriting commission because the underwriters have repurchased the mortgage bonds sold by or for the account of that underwriter in stabilizing or short covering transactions.

These activities by Lehman Brothers Inc. and UBS Securities LLC, on behalf of the other underwriters, may stabilize, maintain or otherwise affect the market price of the mortgage bonds. As a result, the price of the mortgage bonds may be higher than the price that otherwise might exist in the open market. The underwriters make no representation or prediction about any effect that these activities may have on the price of the mortgage bonds. If these activities are commenced, they may be discontinued by Lehman Brothers Inc. and UBS Securities LLC, on behalf of the other underwriters, at any time. These transactions may be effected in the over-the-counter market or otherwise.

Lehman Brothers Inc. and UBS Securities LLC will make securities available for distribution on the internet through a proprietary web site and/or a third-party system operated by MarketAxess Corporation, an internet-based communications technology provider. MarketAxess Corporation is providing the system as a conduit for communications between Lehman Brothers Inc. and UBS Securities LLC and their customers and is not a party to this offering. MarketAxess Corporation, a registered broker-dealer, will receive compensation from Lehman Brothers Inc. and UBS Securities LLC based on transactions conducted through the system. Lehman Brothers Inc. and UBS Securities LLC will make securities available to customers through internet distributions, whether made through a proprietary or third party system, on the same terms as distributions made through other channels.

In the ordinary course of their business, the underwriters and their respective affiliates have engaged, and may in the future engage, in commercial banking and/or investment banking transactions with us and our affiliates. They have received customary fees and commissions for these transactions.

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LEGAL MATTERS

The validity of the mortgage bonds has been passed upon for us by Orrick, Herrington & Sutcliffe LLP, San Francisco, California. Certain legal matters will be passed upon for the underwriters by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York. Skadden, Arps, Slate, Meagher & Flom LLP has in the past performed, and continues to perform, legal services in connection with federal regulatory matters for us and our affiliates.

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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 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 5, 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		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 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 $189 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 12,000 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

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.

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 $189 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

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, provided the following conditions are met:


	•	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 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.

Our Business Strengths

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

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 12,000 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