PACIFIC GAS & ELECTRIC CO - 10-Q Quarterly Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q
(Mark One)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2004 OR

[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to __________

Commission File Number _______________		Exact Name of Registrant as specified in its charter _______________	State or other Jurisdiction of Incorporation ______________	IRS Employer Identification Number ___________

1-12609		PG&E Corporation	California	94-3234914
1-2348		Pacific Gas and Electric Company	California	94-0742640

Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177 ________________________________________			PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, California 94105 ______________________________________
Address of principal executive offices, including zip code

Pacific Gas and Electric Company (415) 973-7000 ________________________________________			PG&E Corporation (415) 267-7000 ______________________________________
Registrant's telephone number, including area code

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

Yes X			No

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes X			No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of latest practicable date.

Common Stock Outstanding, October 27, 2004:
PG&E Corporation			403,127,461 shares (excluding 23,815,500 shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company			Wholly owned by PG&E Corporation

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2004
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE

ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		7
		Condensed Consolidated Balance Sheets		8
		Condensed Consolidated Statements of Cash Flows		10
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		General	11
	NOTE 2:		The Utility's Chapter 11 Filing	21
	NOTE 3:		Debt	25
	NOTE 4:		Discontinued Operations	30
	NOTE 5:		Price Risk Management	31
	NOTE 6:		Commitments and Contingencies	33

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			44
	Results of Operations			51
	Liquidity and Financial Resources			56
	Capital Expenditures and Commitments			61
	Regulatory Matters			64
	Risk Management Activities			74
	Critical Accounting Policies			77
	Taxation Matters			78
	Additional Security Measures			79
	Environmental and Legal Matters			79

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			80
ITEM 4.	CONTROLS AND PROCEDURES			80

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			81
ITEM 2.	CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES			82
ITEM 5.	OTHER INFORMATION			83
ITEM 6.	EXHIBITS			84

SIGNATURES				85

PART I. FINANCIAL INFORMATION
ITEM 1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per share amounts)	(Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,

	2004		2003		2004			2003

Operating Revenues
Electric	$	2,042	$	2,509	$		5,902	$	5,921
Natural gas	581		553		2,198			2,037

Total operating revenues	2,623		3,062		8,100			7,958

Operating Expenses
Cost of electricity	792		661		2,003			1,813
Cost of natural gas	239		234		1,096			1,011
Operating and maintenance	677		678		2,297			2,113
Recognition of regulatory assets	-		-		(4,900)			-
Depreciation, amortization and decommissioning	406		312		1,056			910
Reorganization professional fees and expenses	-		16		6			116

Total operating expenses	2,114		1,901		1,558			5,963

Operating Income	509		1,161		6,542			1,995
Reorganization interest income	-		9		8			36
Interest income	15		6		46			13
Interest expense	(159)		(342)		(565)			(857)
Other income (expense), net	4		7		(46)			21

Income Before Income Taxes	369		841		5,985			1,208
Income tax provision	141		333		2,352			454

Income From Continuing Operations	228		508		3,633			754
Discontinued Operations
Gain/(Loss) from operations of NEGT (net of income tax benefit of $10 million and $230 million for the three and nine months ended September 30, 2003)	-		2		-			(365)

Net Income Before Cumulative Effect of Changes in Accounting Principles
	228		510		3,633			389
Cumulative effect of changes in accounting principles of $(5) million in 2003 related to discontinued operations (net of income tax benefit of $3 million) and $(1) million related to continuing operations (net of income tax of $1 million)
	-		-		-			(6)

Net Income	$	228	$	510	$	3,633		$	383



Weighted Average Common Shares Outstanding, Basic	399		387		397			384

Earnings Per Common Share from Continuing Operations, Basic
	$	0.55	$	1.25	$	8.73		$	1.87



Net Earnings Per Common Share, Basic	$	0.55	$	1.26	$	8.73		$	0.95



Earnings Per Common Share from Continuing Operations, Diluted
	$	0.53	$	1.22	$	8.55		$	1.84



Net Earnings Per Common Share, Diluted	$	0.53	$	1.23	$	8.55		$	0.93




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At

(in millions)	September 30,		December 31,
	2004 (Unaudited)		2003

ASSETS
Current Assets
Cash and cash equivalents	$	1,856	$	3,658
Restricted cash	2,365		403
Accounts receivable:
Customers (net of allowance for doubtful accounts of $63 million in 2004 and $68 million in 2003)	1,958		2,424
Related parties	-		15
Regulatory balancing accounts	849		248
Inventories:
Gas stored underground	226		166
Materials and supplies	127		126
Prepaid expenses and other	57		108

Total current assets	7,438		7,148

Property, Plant and Equipment
Electric	21,192		20,468
Gas	8,468		8,355
Construction work in progress	417		379
Other	18		20

Total property, plant and equipment	30,095		29,222
Accumulated depreciation	(11,395)		(11,115)

Net property, plant and equipment	18,700		18,107

Other Noncurrent Assets
Restricted cash	-		361
Regulatory assets	6,635		2,001
Nuclear decommissioning funds	1,539		1,478
Other	1,058		1,109

Total other noncurrent assets	9,232		4,949

TOTAL ASSETS	$	35,370	$	30,204




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At

(in millions, except share amounts)	September 30,		December 31,
	2004 (Unaudited)		2003

LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Long-term debt, classified as current	$	457	$	310
Rate reduction bonds, classified as current	290		290
Accounts payable:
Trade creditors	485		657
Disputed claims	2,142		-
Regulatory balancing accounts	464		186
Other	444		402
Interest payable	398		174
Income taxes payable	305		256
Other	1,124		899

Total current liabilities	6,109		3,174

Noncurrent Liabilities
Long-term debt	8,726		3,314
Rate reduction bonds	657		870
Regulatory liabilities	3,980		3,979
Asset retirement obligations	1,280		1,218
Deferred income taxes	3,049		856
Deferred tax credits	122		127
Investment in NEGT	1,211		1,216
Preferred stock of subsidiary with mandatory redemption provisions	122		137
Other	1,840		1,494

Total noncurrent liabilities	20,987		13,211

Liabilities Subject to Compromise
Financing debt	-		5,603
Trade creditors	-		3,715

Total liabilities subject to compromise	-		9,318

Commitments and Contingencies (Notes 1, 2, 3, 4, and 6)	-		-
Shareholders' Equity
Preferred stock of subsidiaries	286		286
Preferred stock, no par value, 80,000,000 shares, $100 par value, 5,000,000 shares, none issued	-		-
Common stock, no par value, authorized 800,000,000 shares, issued 425,035,028 common and 1,613,067 restricted shares in 2004 and 412,147,679 common and 1,577,770 restricted shares in 2003	6,609		6,468
Common stock held by subsidiary, at cost, 23,815,500 shares	(690)		(690)
Unearned compensation	(25)		(20)
Accumulated earnings (deficit)	2,175		(1,458)
Accumulated other comprehensive loss	(81)		(85)

Total shareholders' equity	8,274		4,501

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	35,370	$	30,204




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)

	Nine Months Ended
(in millions)	September 30,

	2004		2003

Cash Flows From Operating Activities
Net income (loss)	$	3,633	$	383
Loss from discontinued operations	-		365
Cumulative effect of changes in accounting principles	-		6

Net income from continuing operations	3,633		754
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and decommissioning	1,056		910
Recognition of regulatory assets	(4,900)		-
Deferred income taxes and tax credits, net	2,360		339
Other deferred charges and noncurrent liabilities	(183)		636
Loss from retirement of long-term debt	-		89
Gain on sale of assets	(18)		(10)
Net effect of changes in operating assets and liabilities:
Restricted cash	150		(28)
Accounts receivable - customer	42		(23)
Inventories	(61)		(96)
Accounts payable - trade	78		262
Accrued taxes	4		517
Regulatory balancing accounts, net	(323)		(397)
Other working capital	572		(26)
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	(1,022)		(83)
Other, net	102		72

Net cash provided by operating activities	1,490		2,916

Cash Flows From Investing Activities
Capital expenditures	(1,110)		(1,183)
Proceeds from sale of assets	28		14
Increase in restricted cash	(1,751)		-
Other, net	(55)		(24)

Net cash used in investing activities	(2,888)		(1,193)

Cash Flows From Financing Activities
Proceeds from issuance of long-term debt, net of issuance costs of $74 million	7,346		582
Long-term debt matured, redeemed or repurchased	(7,553)		(1,067)
Rate reduction bonds matured	(213)		(213)
Preferred stock with mandatory redemption provisions redeemed	(15)		-
Preferred dividends paid	(88)		-
Common stock issued	121		120
Other, net	(2)		(2)

Net cash provided by (used in) financing activities	(404)		(580)

Net change in cash and cash equivalents	(1,802)		1,143
Cash and cash equivalents at January 1	3,658		3,532

Cash and cash equivalents at September 30	$	1,856	$	4,675



Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	13	$	30
Cash paid for:
Interest (net of amounts capitalized)		522		555
Income taxes paid, net		96		(531)
Reorganization professional fees and expenses		21		84
Supplemental disclosures of noncash investing and financing activities
Transfer of liabilities and other payables subject to compromise from operating assets and liabilities
		(2,877)		193
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions)
		(Unaudited)

		Three Months Ended				Nine Months Ended
		September 30,				September 30,

		2004		2003		2004		2003

Operating Revenues
Electric	$		2,042	$	2,509	$	5,902	$	5,921
Natural gas		581		553		2,198		2,040

Total operating revenues		2,623		3,062		8,100		7,961

Operating Expenses
Cost of electricity		792		661		2,003		1,823
Cost of natural gas		239		234		1,096		1,040
Operating and maintenance		671		657		2,271		2,098
Recognition of regulatory assets		-		-		(4,900)		-
Depreciation, amortization, and decommissioning		405		311		1,054		916
Reorganization professional fees and expenses		-		16		6		116

Total operating expenses		2,107		1,879		1,530		5,993

Operating Income		516		1,183		6,570		1,968
Reorganization interest income		-		9		8		36
Interest income		11		2		36		6
Interest expense (noncontractual interest expense of $31 million for the nine months ended September 30, 2004, and $32 million and $99 million for the three and nine months ended September 30, 2003, respectively)
		(141)		(237)		(512)		(681)
Other income, net		14		15		43		41

Income Before Income Taxes		400		972		6,145		1,370
Income tax provision		152		383		2,410		508

Income Before Cumulative Effect of a Change in Accounting Principle		248		589		3,735		862
Cumulative effect of change in accounting principle (net of income tax benefit of $1 million for the nine months ended September 30, 2003)
		-		-		-		(1)

Net Income		248		589		3,735		861
Preferred dividend requirement		4		6		17		18

Income Available for Common Stock	$		244	$	583	$	3,718	$	843




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

	Balance At

(in millions)	September 30,		December 31,
	2004 (Unaudited)		2003

ASSETS
Current Assets
Cash and cash equivalents	$	980	$	2,979
Restricted cash	2,004		403
Accounts receivable:
Customers (net of allowance for doubtful accounts of $63 million in 2004 and $68 million in 2003)	1,958		2,424
Related parties	3		17
Regulatory balancing accounts	849		248
Inventories:
Gas stored underground	226		166
Materials and supplies	127		126
Prepaid expenses and other	53		100

Total current assets	6,200		6,463

Property, Plant and Equipment
Electric	21,193		20,468
Gas	8,467		8,355
Construction work in progress	417		379

Total property, plant and equipment	30,077		29,202
Accumulated depreciation	(11,377)		(11,100)

Net property, plant and equipment	18,700		18,102

Other Noncurrent Assets
Regulatory assets	6,635		2,001
Nuclear decommissioning funds	1,539		1,478
Other	997		1,051

Total other noncurrent assets	9,171		4,530

TOTAL ASSETS	$	34,071	$	29,095




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS

		Balance At

(in millions, except share amounts)		September 30,		December 31,
		2004 (Unaudited)		2003

LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Long-term debt, classified as current		$	457	$	310
Rate reduction bonds, classified as current		290		290
Accounts payable:
Trade creditors		484		657
Disputed claims		2,142		-
Related parties		33		224
Regulatory balancing accounts		464		186
Other		423		365
Interest payable		383		153
Income taxes payable		131		-
Deferred income taxes		253		86
Other		817		673

Total current liabilities		5,877		2,944

Noncurrent Liabilities
Long-term debt		7,844		2,431
Rate reduction bonds		657		870
Regulatory liabilities		3,980		3,979
Asset retirement obligations		1,280		1,218
Deferred income taxes		3,567		1,334
Deferred tax credits		122		127
Preferred stock with mandatory redemption provisions		122		137
Other		1,736		1,464

Total noncurrent liabilities		19,308		11,560

Liabilities Subject to Compromise
Financing debt		-		5,603
Trade creditors		-		3,899

Total liabilities subject to compromise		-		9,502

Commitments and Contingencies (Notes 1, 2, 3 and 6)		-		-

Shareholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable, 5% to 6%, outstanding 5,784,825 shares	145			145
Redeemable, 4.36% to 7.04%, outstanding 5,973,456 shares	149			149
Common stock, $5 par value, authorized 800,000,000 shares,
issued 321,314,760 shares	1,606			1,606
Common stock held by subsidiary, at cost, 19,481,213 shares	(475)			(475)
Additional paid-in capital	2,040			1,964
Reinvested earnings	5,424			1,706
Accumulated other comprehensive loss	(3)			(6)

Total shareholders' equity	8,886			5,089

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$		34,071	$	29,095




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)

	Nine Months Ended
(in millions)	September 30,

	2004		2003

Cash Flows From Operating Activities
Net income	$	3,735	$		861
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and decommissioning	1,054		916
Recognition of regulatory assets	(4,900)		-
Deferred income taxes and tax credits, net	2,395		122
Other deferred charges and noncurrent liabilities	(121)		395
Gain on sale of assets	(18)		(10)
Cumulative effect of a change in accounting principle	-		2
Net effect of changes in operating assets and liabilities:
Restricted cash	150		(44)
Accounts receivable	42		(8)
Inventories	(61)		(96)
Accounts payable	77		350
Accrued taxes	87		437
Regulatory balancing accounts, net	(323)		(397)
Other working capital	285		77
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	(1,022)		(83)
Other, net	28		17

Net cash provided by operating activities	1,408		2,539

Cash Flows From Investing Activities
Capital expenditures	(1,110)		(1,182)
Proceeds from sale of assets	28		14
Increase in restricted cash	(1,751)		-
Other, net	(50)		(25)

Net cash used in investing activities	(2,883)		(1,193)

Cash Flows From Financing Activities
Proceeds from issuance of long-term debt, net of issuance costs of $74 million	7,346		-
Long-term debt matured, redeemed or repurchased	(7,552)		(280)
Rate reduction bonds matured	(213)		(213)
Preferred dividends paid	(88)		-
Preferred stock with mandatory redemption provisions redeemed	(15)		-
Other, net	(2)		(1)

Net cash used in financing activities	(524)		(494)


Net change in cash and cash equivalents	(1,999)		852
Cash and cash equivalents at January 1	2,979		3,343

Cash and cash equivalents at September 30	$	980	$		4,195




Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	13	$		30
Cash paid for:
Interest (net of amounts capitalized)	466		475
Income taxes paid (refunded), net	94			(32)
Reorganization professional fees and expenses	21		84
Supplemental disclosures of noncash investing and financing activities
Transfer of liabilities and other payables subject to compromise (to) from operating assets and liabilities, net	(2,877)		193

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: GENERAL

Organization and Basis of Presentation

As discussed further in Note 2, on April 12, 2004, the Utility's plan of reorganization, or Plan of Reorganization, under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, became effective, at which time the Utility emerged from Chapter 11.

PG&E Corporation's other significant subsidiary, National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., headquartered in Bethesda, Maryland, was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. On July 8, 2003, NEGT filed a voluntary petition for relief under Chapter 11. For the reasons described below in Note 4, PG&E Corporation considers NEGT to be an abandoned asset under Statement of Financial Accounting Standards, or SFAS, "Accounting for Impairment or Disposal of Long-Lived Assets," or SFAS No. 144, and, as a result, the operations of NEGT prior to July 8, 2003 and for all prior periods, are reflected as discontinued operations in the Consolidated Financial Statements. In addition, as discussed in Note 4, effective July 8, 2003, PG&E Corporation no longer consolidates the earnings and losses of NEGT or its subsidiaries and began accounting for its ownership interest in NEGT using the cost method, under which PG&E Corporation's investment in NEGT is reflected as a single amount on the Condensed Consolidated Balance Sheet of PG&E Corporation. On October 29, 2004, NEGT's plan of reorganization became effective and NEGT emerged from Chapter 11, at which time PG&E Corporation's equity interest in NEGT was cancelled.

This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and the Utility. Therefore, the Notes to the unaudited Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility's Condensed Consolidated Financial Statements include its accounts and those of its wholly owned and controlled subsidiaries, and variable interest entities for which it is subject to a majority of the risk of loss or gain.

The accompanying interim unaudited Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP, for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they may not contain all of the information and footnotes required by GAAP for complete financial statements. Both PG&E Corporation's and the Utility's Consolidated Balance Sheets at December 31, 2003, were derived from the audited Consolidated Balance Sheets included in the Current Report on Form 8-K dated June 18, 2004 (which supercedes the information included in the combined 2003 Annual Report). Certain reclassifications of the 2003 amounts have been made to conform to the 2004 presentation.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets and liabilities and the disclosure of contingencies, and include, but are not limited to, estimates in determining the Utility's regulatory asset and liability balances based on probability assessments, revenues earned but not yet billed (including delayed billings), asset retirement obligations, allowance for doubtful accounts receivable, provisions for losses that are deemed probable from environmental remediation liabilities, pension liabilities, mark-to-market accounting under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, or SFAS No. 133, income taxes, litigation, and in the Utility's review for impairment of long-lived assets and certain identifiable intangibles to be held and used whenever events or changes in circumstances indicate that the carrying amount of its assets might not be recoverable. As these estimates involve judgments on a wide range of factors, including future economic conditions that are difficult to predict, actual results could differ from these estimates. PG&E Corporation's and the Utility's Consolidated Financial Statements reflect all adjustments that management believes are necessary for the fair presentation of the financial position and results of operations for the interim periods presented. These adjustments are of a normal recurring nature.

During the period that the Utility was in Chapter 11, the Utility's Consolidated Financial Statements were prepared 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. Under SOP 90-7, certain claims against the Utility existing before the Utility's Chapter 11 filing were classified as liabilities subject to compromise on PG&E Corporation's and the Utility's Consolidated Balance Sheets. Additionally, professional fees and expenses directly related to the Utility's Chapter 11 proceeding and interest income on funds accumulated during the Chapter 11 proceedings were reported separately as reorganization items.

The Utility discontinued the application of SOP 90-7 upon its emergence from Chapter 11 on April 12, 2004. The Consolidated Financial Statements as of and for the periods ending September 30, 2003 and December 31, 2003, have been presented in accordance with SOP 90-7. Although the Utility emerged from Chapter 11 on April 12, 2004, the bankruptcy court retained jurisdiction, among other things, to resolve disputed claims made in the Chapter 11 case. Upon the effective date of the Utility's Plan of Reorganization, $1.8 billion was deposited into escrow, pending the resolution of disputed claims, and has been classified as restricted cash in current assets on PG&E Corporation's and the Utility's September 30, 2004 Consolidated Balance Sheets. The related remaining pre-petition claims are subject to resolution by the bankruptcy court.

Adoption of New Accounting Policies and Summary of Significant Accounting Policies

The accounting policies used by the Utility include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC. Except as disclosed below, PG&E Corporation and the Utility are following the same accounting policies discussed in their Current Report on Form 8-K dated June 18, 2004 (which supercedes the information included in the combined 2003 Annual Report).

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

In May 2004, the Financial Accounting Standards Board, or the FASB, issued Staff Position SFAS No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," or FSP 106-2. FSP 106-2 supersedes FSP 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," and provides guidance on the accounting, disclosure, effective date, and transition requirements related to the Medicare Prescription Drug Act. FSP 106-2 is effective for the third quarter of 2004. The companies have determined that the Utility's postretirement medical plan, or the Plan, the only benefit plan potentially affected by the Medicare Prescription Drug Act (and FSP 106-2), does not qualify for the federal subsidy under the terms of the Medicare Prescription Drug Act. The adoption of FSP 106-2 did not hav e any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility. The Medicare Prescription Drug Act could subsequently affect the Plan in terms of lower participation rates, which would lower the Plan's benefit obligation and related expenses.

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. FIN 46R provides that an entity is a variable interest entity, or VIE, if it does not have sufficient equity investment at risk, or if the holders of the entity's equity instruments lack the essential characteristics of a controlling financial interest. FIN 46R requires that the company that is subject to a majority of the risk of loss from a VIE's activities, or is entitled to receive a majority of the entity's residual returns, or both, consolidate the VIE. A company that consolidates a VIE is called the primary beneficiary.

PG&E Corporation and the Utility adopted FIN 46R on January 1, 2004. The adoption of FIN 46R did not have any impact on net income.

Low-Income Housing Partnerships

The Utility invests in low-income housing partnerships, or LIHPs. The entities were formed to invest in low-income housing projects sponsored by non-profit organizations in the state of California. The Utility determined that it was the primary beneficiary of one LIHP, resulting in its consolidation. Accordingly, total assets and total liabilities of $14 million for the LIHP have been included in the Utility's Consolidated Balance Sheets. The consolidated LIHP has issued debt in the amount of $6 million, which is secured by assets of the partnership, totaling $27 million, and the Utility's commitment to make capital infusions of approximately $13 million over the next five years.

The Utility is not considered to be the primary beneficiary of any other LIHPs. The maximum exposure to loss from its investment in unconsolidated LIHPs is the Utility's investment of $6 million.

Power Purchase Agreements

The nature of power purchase agreements is such that the Utility could have a significant variable interest in a power purchase agreement counterparty if that entity is a VIE owning one plant that sells substantially all of its output to the Utility, and the contract price for power is correlated with the plant's variable costs of production. Previously, the Utility was not able to determine whether certain power purchase contracts represented variable interests in VIEs. During the third quarter, the Utility determined that none of its current power purchase agreements represent significant variable interests. The Emerging Issues Taskforce, or the EITF, continues to review how companies determine whether an arrangement is a variable interest. Their findings could impact how the determination is applied to the Utility's power purchase agreements in the future.

Changes in Accounting for Certain Derivative Contracts

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

PG&E Corporation and the Utility had previously adopted the new DIG C15 guidelines prospectively for new derivative instruments entered into after June 30, 2003. On January 1, 2004, PG&E Corporation and the Utility adopted the new DIG C15 guidelines for certain power contracts that contain option-like features that existed prior to July 1, 2003. The adoption of DIG C15 did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

Regulation and Statement of Financial Accounting Standards No. 71

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with "Accounting for the Effects of Certain Types of Regulation," as amended, or SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the costs of providing service. The Utility is regulated by the CPUC, the FERC and the Nuclear Regulatory Commission, or the NRC, among others. As discussed further in Note 2, during the first quarter of 2004, the Utility began reapplying SFAS No. 71 to its generation operations. As a result, as of March 31, 2004, the Utility recorded a generation regulatory asset of approximately $1.2 billion. SFAS No. 71 now applies to all of the Utility's operations except for the operations of a natural gas pipeline.

SFAS No. 71 provides for recording regulatory assets and liabilities when certain conditions are met. Regulatory assets represent the capitalization of incurred costs that would otherwise be charged to expense when it is probable that the incurred costs would be included for ratemaking purposes in the future. Regulatory liabilities represent rate actions of a regulator that will result in amounts that are to be credited to customers through the ratemaking process.

To the extent that portions of the Utility's operations cease to be subject to SFAS No. 71 or recovery is no longer probable as a result of changes in regulation or the Utility's competitive position, the related regulatory assets and liabilities are written off.

Regulatory Assets

Regulatory assets comprise the following:

(in millions)	September 30, 2004		December 31, 2003

Settlement Regulatory Asset	$	3,256	$	-
Utility retained generation regulatory assets		1,200		-
Rate reduction bond assets	815		1,054
Regulatory assets for deferred income tax	470		324
Unamortized loss, net of gain, on reacquired debt	351		277
Qualifying facilities restructuring costs	144		151
Environmental compliance costs	177		139
Regulatory assets associated with Plan of Reorganization	174		-
Other, net	48		56

Total regulatory assets	$	6,635	$		2,001

Amortization of regulatory assets is charged to expense during the period that the costs are reflected in regulated revenues. In light of the satisfaction of various conditions to the implementation of the Plan of Reorganization, the accounting probability standard required to be met under SFAS No. 71 in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement (as described in Note 2) was met as of March 31, 2004. Therefore, the Utility recorded the $3.7 billion, pre-tax ($2.2 billion, after-tax), regulatory asset established under the Settlement Agreement, or the Settlement Regulatory Asset, and $1.2 billion, pre-tax ($0.7 billion, after-tax), for the Utility retained generation regulatory assets in the first quarter of 2004 (see further discussion in Note 2, The Utility's Chapter 11 filing). As of September 30, 2004, the Utility has recorded pre-tax offsets to the Settlement Regulatory Asset of approximately $300 million ($180 million after-tax) for supplier settlements and approximately $110 million ($65 million after-tax) for amortization of the Settlement Regulatory Asset.

Regulatory Liabilities

Regulatory liabilities comprise the following:

(in millions)	September 30, 2004		December 31, 2003

Cost of removal obligations	$	1,942	$	1,810
Employee benefit plans	726		925
Asset retirement costs	626		584
Public purpose programs	203		185
Rate reduction bonds	177		175
Surcharge liability	128		125
Other	178		175

Total regulatory liabilities	$	3,980	$	3,979

Regulatory Balancing Accounts

Sales balancing accounts accumulate differences between revenues and the Utility's authorized revenue requirements. Cost balancing accounts accumulate differences between incurred costs and authorized revenue requirements. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being credited to customers are recorded as regulatory balancing account liabilities. The Utility's regulatory balancing accounts accumulate balances until they are refunded to or received from the Utility's customers through authorized rate adjustments.

Earnings (Loss) Per Share

Earnings (loss) per share is calculated utilizing the "two-class" method by dividing earnings (loss) allocated to common shareholders by the weighted average number of common shares outstanding during the period.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,

(in millions, except per share amounts)	2004		2003		2004		2003

Income from continuing operations	$	228	$	508	$	3,633	$	754
Discontinued operations		-		2		-		(365)

Net income before cumulative effect of changes in accounting principles		228	510		3,633		389
Cumulative effect of changes in accounting principles		-	-		-		(6)

Net Income for basic and diluted calculations	$	228	$	510	$	3,633	$	383




Weighted average common shares outstanding, basic		399		387		397		384
9.50% Convertible Subordinated Notes		19		19		19		19

Weighted average common shares outstanding and participating securities, basic		418		406		416		403




Weighted average common shares outstanding, basic		399		387		397		384
Employee stock options and PG&E Corporation shares held by grantor trusts		7		5		6		2
PG&E Corporation warrants		2		5		3		5

Weighted average common shares outstanding, diluted		408		397		406		391
9.50% Convertible Subordinated Notes		19		19		19		19

Weighted average common shares outstanding and participating securities, diluted		427		416		425		410



Earnings (Loss) Per Common Share, Basic
Income from continuing operations	$	0.55	$	1.25	$	8.73	$	1.87
Discontinued operations		-		-		-		(0.91)
Cumulative effect of changes in accounting principles		-		-		-		(0.01)
Rounding		-		0.01		-		-

Net earnings	$	0.55	$	1.26	$	8.73	$	0.95



Earnings (Loss) Per Common Share, Diluted
Income from continuing operations	$	0.53	$	1.22	$	8.55	$	1.84
Discontinued operations		-		-		-		(0.89)
Cumulative effect of changes in accounting principles		-		-		-		(0.01)
Rounding		-		0.01		-		(0.01)

Net earnings	$	0.53	$	1.23	$	8.55	$	0.93

On March 31, 2004, the FASB ratified the consensus reached by the EITF, on EITF Issue 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06. EITF 03-06 provides additional guidance related to the calculation of earnings per share under SFAS No. 128, "Earnings per Share," or SFAS No. 128, which includes application of the "two-class" method in computing earnings per share, identification of participating securities, and requirements for the allocation of undistributed earnings (and losses) to participating securities.

PG&E Corporation currently has outstanding $280 million in convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes meet the criteria of a participating security in the calculation of basic earnings per share using the "two-class" method of SFAS No. 128. Therefore, EITF 03-06 requires that earnings be allocated between common stock and the participating security. PG&E Corporation adopted EITF 03-06 in the first quarter of 2004 and for all subsequent and all prior periods presented.

In applying the "two-class" method, the following reflects the earnings (loss) allocated to common shareholders after the inclusion of participation rights related to PG&E Corporation's 9.50% Convertible Notes in the allocation of earnings. The 9.50% Convertible Notes are convertible at the option of the holders into 18,558,655 common shares. All PG&E Corporation's participating securities participate on a 1:1 basis in dividends with common shareholders.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,

Earnings (loss) allocated to common shareholders, basic	2004		2003		2004		2003

Income from continuing operations	$	218	$	484	$	3,467	$	718
Discontinued operations		-		2		-		(348)
Cumulative effect of changes in accounting principles		-		-		-		(6)

	$	218	$	486	$	3,467	$	364




Earnings (loss) allocated to common shareholders, diluted
Income from continuing operations	$	218	$	485	$	3,471	$	719
Discontinued operations		-		2		-		(348)
Cumulative effect of changes in accounting principles		-		-		-		(6)

	$	218	$	487	$	3,471	$	365

The following options to purchase PG&E Corporation common shares were outstanding, but not included in the computation of diluted earnings per share because the option exercise prices were greater than the average market price: nine months ended September 30, 2004 - 8,045,805, nine months ended September 30, 2003 - 17,687,167, three months ended September 30, 2004 - 7,705,881, and three months ended September 30, 2003 - 11,130,315.

PG&E Corporation reflects the preferred dividends of subsidiaries as other expense for computation of both basic and diluted earnings per share.

Stock-Based Compensation

PG&E Corporation and the Utility apply the intrinsic-value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," in accounting for employee stock-based compensation, as allowed by SFAS No. 123, "Accounting for Stock-Based Compensation," or SFAS No. 123, as amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure, an Amendment of FASB Statement No. 123," or SFAS No. 148. Under the intrinsic value method, PG&E Corporation and the Utility do not recognize any compensation expense for stock options, as the exercise price is equal to the fair market value of a share of PG&E Corporation common stock at the time the options are granted.

The tables below show the effect on net income and earnings per share for PG&E Corporation and the Utility had it elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123 for the three and nine months ended September 30, 2004 and 2003:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,

(in millions, except per share amounts)			2004		2003		2004		2003
Net Earnings:
As reported			$	228	$	510	$	3,633	$	383
	Deduct: Total stock-based employee compensation expense
		determined under the fair value based method for all awards,
		net of related tax effects		3		4		10		11

Pro forma			$	225	$	506	$	3,623	$	372




Basic earnings per share:
As reported				0.55		1.26		8.73		0.95
Pro forma				0.54		1.25		8.71		0.92

Diluted earnings per share:
As reported				0.53		1.23		8.55		0.93
Pro forma				0.53		1.23		8.57		0.92

If compensation expense had been recognized using the fair value-based method under SFAS No. 123, the Utility's pro forma consolidated earnings would have been as follows:

			Three Months Ended				Nine Months Ended
			September 30,				September 30,

(in millions)			2004		2003		2004		2003
Net Earnings:
As reported			$	244	$	583	$	3,718	$	843
	Deduct: Total stock-based employee compensation expense
		determined under the fair value based method for all awards,
		net of related tax effects		2		2		6		6

Pro forma			$	242	$	581	$	3,712	$	837

At September 30, 2004, a total of 2,088,920 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries, of which 1,280,000 shares were granted to Utility employees. At September 30, 2004, approximately 1,613,427 shares of restricted stock awarded to eligible employees of PG&E Corporation and its subsidiaries were outstanding, of which 1,062,697 shares were granted to Utility employees. The shares were granted with restrictions and are subject to forfeiture unless certain conditions are met.

The restricted shares are held in an escrow account. The shares become available to the employees as the restrictions lapse. In general, for shares granted in 2003, the restrictions on 80% of the shares lapse automatically over a period of four years at the rate of 20% per year. The compensation expense for these shares remains fixed at the value of the stock at grant date. Restrictions on the remaining 20% of the shares will lapse at a rate of 5% per year if PG&E Corporation is in the top quartile of its comparator group as measured by annual total shareholder return for each year ending immediately before each annual lapse date. The compensation expense recognized for these shares is variable, and changes with the common stock share price. For shares granted in 2004, the restrictions lapse automatically over a period of four years at the rate of 25% per year, and the compensation expense remains fixed at the value of the stock at grant date. Compensation expense associated with all restricted stock is recognized on a quarterly basis by amortizing the unearned compensation related to that period. Total compensation expense resulting from the restricted stock issuances reflected in PG&E Corporation's Consolidated Statements of Income was approximately $3.1 million for the three-month period ended September 30, 2004 and $6.2 million for the nine-month period ended September 30, 2004, of which approximately $1.8 million for the three-month period ended September 30, 2004 and $3.8 million for the nine-month period ended September 30, 2004 was recognized by the Utility. The total unamortized balance of unearned compensation resulting from the restricted stock issuances reflected in PG&E Corporation's Consolidated Balance Sheet at September 30, 2004 was approximately $25 million.

Comprehensive Income (Loss)

PG&E Corporation's and the Utility's comprehensive income (loss) consists principally of changes in the market value of certain cash flow hedges under SFAS No. 133, and the effects of the remeasurement of the defined benefit pension plan.

	PG&E Corporation				Utility

(in millions)	2004		2003		2004		2003

Three months ended September 30
Net income available for common stock	$	228	$	510	$	244	$	583
Net reclassification from OCI to earnings (net of income tax expense of $1 million in 2003)	-		2		-		-
Other		-		1		-		-

Comprehensive income	$	228	$	513	$	244	$	583




Nine months ended September 30
Net income available for common stock	$	3,633	$	383	$	3,718	$	843
Net gain (loss) in OCI from current period hedging transactions and price changes in accordance with SFAS No. 133 (net of income tax expense of $2 million in 2004 and benefit of $4 million in 2003)	3		(5)		3		-
Net reclassification from OCI to earnings (net of income tax benefit of $3 million in 2003)	-		17		-		-
Foreign currency translation adjustment (net of income tax expense of $2 million in 2003)	-		3		-		-
Retirement plan remeasurement (net of income tax benefit of $41 million in 2003)		-		(60)		-		(60)
Other		1		1		-		-

Comprehensive income	$	3,637	$	339	$	3,721	$	783

The above changes to other comprehensive income, or OCI, are stated net of income tax expense (benefit) of $2 million for the nine-month period ended September 30, 2004, and $1 million for the three-month and ($46) million for the nine-month periods ended September 30, 2003.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of an enterprise that results from transactions and other economic events other than transactions with shareholders. The following table sets forth the changes in each component of accumulated other comprehensive income (loss):

	Hedging Transactions in Accordance with SFAS No. 133		Foreign Currency Translation Adjustment		Retirement Plan Remeasurement		Other		Accumulated Other Comprehensive Income (Loss)

Balance at December 31, 2002	$	(90)	$	(3)	$	-	$	-	$	(93)
Period change in:
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133	(5)		-		-		-		(5)
Net reclassification to earnings	17		-		-		-		17
Other	-		3		(60)		1		(56)

Balance at September 30, 2003	$	(78)	$	-	$	(60)	$	1	$	(137)



Balance at December 31, 2003	$	(81)	$	-	$	(4)	$	-	$	(85)
Period change in:
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133	3		-		-		-		3
Other	-		-		-		1		1

Balance at September 30, 2004	$	(78)	$	-	$	(4)	$	1	$	(81)

	Hedging Transactions in Accordance with SFAS No. 133		Foreign Currency Translation Adjustment		Retirement Plan Remeasurement		Other		Accumulated Other Comprehensive Income (Loss)

Balance at June 30, 2003	$	(80)	$	-	$	(60)	$	-	$	(140)
Net reclassification to earnings	2		-		-		-		2
Other	-		-		-		1		1

Balance at September 30, 2003	$	(78)	$	-	$	(60)	$	1	$	(137)



Balance at June 30 and September 30, 2004	$	(78)	$	-	$	(4)	$	1	$	(81)

There was no movement in the component balances of accumulated other comprehensive income (loss) during the third quarter of 2004. An amount of $77 million is included in accumulated other comprehensive income (loss) related to discontinued operations at September 30, 2004, and at September 30, 2003. This amount will be recognized in connection with PG&E Corporation's elimination of its equity interest in NEGT in the fourth quarter of 2004 (see further discussion in Note 4, Discontinued Operations).

Related Party Agreements and Transactions

In accordance with various agreements, the Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional support services in support of operations. These services are priced either at the fully loaded cost (i.e., direct costs and allocation of overhead costs) or at the higher of fully loaded cost or fair market value, depending on the nature of the services. PG&E Corporation also allocates certain other corporate administrative and general costs to the Utility and other subsidiaries using a variety of factors, including the number of employees, operating expenses excluding fuel purchases, total assets and other cost-causal methods. The Utility purchases natural gas transportation services from Gas Transmission Northwest Corporation, or GTNW, formerly known as PG&E Gas Transmission, Northwest Corporation. Effective April 1, 2003, the Utility no longer purchases natural gas from NEGT Energy Trading Holdings Corporation, or NEGT ET, formerly known as PG&E Energy Trading Holdings Corporation. Both GTNW and NEGT ET are subsidiaries of NEGT. The Utility sold natural gas transportation capacity and other ancillary services to NEGT ET until NEGT's Chapter 11 proceeding was imminent. These services were priced at either tariff rates or fair market value, depending on the nature of the services provided. Through July 7, 2003, all significant intercompany transactions are eliminated in consolidation; therefore, no profit or loss resulted from these transactions. Beginning July 8, 2003, the Utility's transactions with NEGT are no longer eliminated in consolidation. The Utility's significant related party transactions and related receivable (payable) balances were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,				Receivable (Payable) Balance Outstanding at
	Three Months Ended September 30,				Nine Months Ended September 30,				September 30,		December 31,

(in millions)	2004		2003		2004		2003		2004		2003

Utility revenues from:
Administrative services provided to PG&E Corporation	$	2	$	2	$	6	$	6	$	2	$	-
Natural gas transportation capacity services provided to NEGT ET		-		2		-		6		-		-
Trade deposit due from GTNW		-		-		-		-		-		15
Utility expenses from:
Administrative services received from PG&E Corporation	$	23	$	40	$	65	$	137	$	(27)	$	(396)
Interest accrued on pre-petition liability due to PG&E Corporation		-		2		2		5		-		(2)
Administrative services received from NEGT		-		-		-		2		-		(1)
Software purchases from NEGT		-		-		-		1		-		-
Gas commodity services received from NEGT ET		-		-		-		10		-		-
Gas transportation services received from GTNW		14		14		43		43		(5)		(8)

As discussed further in Note 2, as of March 31, 2004, PG&E Corporation recorded the impact of the Settlement Agreement entered into on December 19, 2003, among PG&E Corporation, the Utility and the CPUC to resolve the Utility's Chapter 11 case. The Settlement Agreement precluded the Utility from reimbursing PG&E Corporation for certain Chapter 11 related costs. As such, PG&E Corporation reduced its receivable from the Utility, and the Utility reduced its payable to PG&E Corporation by $128 million. The transactions were recorded as a contribution of equity to the Utility by PG&E Corporation, net of taxes of $52 million, and an increase to additional paid-in capital by the Utility in the first quarter of 2004.

Pension and Other Postretirement Benefits

PG&E Corporation and its subsidiaries provide non-contributory defined benefit pension plans for certain of their employees and retirees (referred to collectively as pension benefits), contributory postretirement medical plans for certain of their employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for certain of their employees and retirees (referred to collectively as other benefits). PG&E Corporation and its subsidiaries use a December 31 measurement date for all of its plans and use publicly quoted market values and independent pricing services depending on the nature of the assets, as reported by the trustee, to determine the fair value of the plan assets.

Net periodic benefit cost as reflected in PG&E Corporation's and the Utility's Statements of Income for the three and nine-month periods ended September 30, 2004 and September 30, 2003 are as follows:

PG&E Corporation

	Pension Benefits Three Months Ended September 30				Other Benefits Three Months Ended September 30

(in millions)	2004		2003		2004			2003


Service cost for benefits earned	$	49	$	42	$	8	$		7
Interest cost	120		111		21		20
Expected return on plan assets	(140)		(126)		(19)		(15)
Amortization of transition obligation	1		3		6		7
Amortization of prior service cost	14		11		3		-
Amortization of recognized loss	2		11		-		-

Net periodic benefit cost	$	46	$	52	$	19	$		19

	Pension Benefits Nine Months Ended September 30				Other Benefits Nine Months Ended September 30

(in millions)	2004		2003		2004		2003


Service cost for benefits earned	$	146	$	127	$	24	$	22
Interest cost	361		335		63		59
Expected return on plan assets	(422)		(381)		(57)		(46)
Amortization of transition obligation	4		10		19		19
Amortization of prior service cost	41		32		9		1
Amortization of recognized loss	6		34		-		1
Settlement loss	1		2		-		-

Net periodic benefit cost	$	137	$	159	$	58	$	56

Utility

	Pension Benefits Three Months Ended September 30				Other Benefits Three Months Ended September 30

(in millions)	2004		2003		2004		2003


Service cost for benefits earned	$	48	$	42	$	8	$	7
Interest cost	119		110		21		20
Expected return on plan assets	(140)		(126)		(19)		(15)
Amortization of transition obligation	1		3		6		7
Amortization of prior service cost	14		11		3		-
Amortization of recognized loss	2		11		-		-

Net periodic benefit cost	$	44	$	51	$	19	$	19

	Pension Benefits Nine Months Ended September 30				Other Benefits Nine Months Ended September 30

(in millions)	2004		2003		2004		2003


Service cost for benefits earned	$	143	$	125	$	24	$	22
Interest cost	358		332		63		59
Expected return on plan assets	(420)		(379)		(57)		(46)
Amortization of transition obligation	4		10		19		19
Amortization of prior service cost	41		32		9		1
Amortization of recognized loss	6		34		-		1
Settlement loss	1		1		-		-

Net periodic benefit cost	$	133	$	155	$	58	$	56

Under SFAS No. 71, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach.

In August 2004, the Utility contributed approximately $20 million to its pension benefit plan. No further contributions are expected during the fiscal year 2004. The Utility's pension benefit plans met all the funding requirements under the Employee Retirement Income Security Act of 1974, as amended.

NOTE 2: THE UTILITY'S CHAPTER 11 FILING

Emergence From Chapter 11

On April 12, 2004, the Utility's Plan of Reorganization under Chapter 11 of the U.S. Bankruptcy Code became effective, at which time the Utility emerged from Chapter 11. The Plan of Reorganization incorporated the terms of the settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement. Although the Utility's operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the Plan of Reorganization, and (3) the bankruptcy court's December 22, 2003 order confirming the Plan of Reorganization. In addition, the bankruptcy court retains jurisdiction to re solve remaining disputed claims.

In anticipation of its emergence from Chapter 11, the Utility consummated its public offering of $6.7 billion of first mortgage bonds, or First Mortgage Bonds, on March 23, 2004. Upon the effectiveness of the Plan of Reorganization, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their resolution, reinstated certain obligations, and paid other obligations. The following table summarizes the sources and uses of funds on the effective date:

(in millions)
Sources			Uses


First Mortgage Bonds	$	6,700	Payments to Creditors	$	8,394
Term Loans	799		Disputed Claims Escrow	1,843
Accounts Receivable Financing Facility	350

Total Debt Financing	7,849
Cash Used to Pay Claims	2,388

Sources of Funds for Claims	10,237		Uses of Funds for Claims	10,237

Reinstated Pollution Control Bond-Related Obligations	814		Reinstated Pollution Control Bond-Related Obligations	814
Reinstated Preferred Stock	421		Reinstated Preferred Stock	421
Cash on Hand	225		Preferred Dividends	93
			Environmental Measures	10
			Transaction Costs	122

Total Sources of Funds	$	11,697	Total Uses of Funds	$	11,697

In connection with the Utility's emergence from Chapter 11, the Utility received investment-grade issuer credit ratings of Baa3 from Moody's Investors Service, or Moody's, and BBB- from Standard & Poor's, or S&P.

On July 15, 2004, the U.S. District Court for the Northern District of California, or the District Court, dismissed the appeals of the bankruptcy court's order confirming the Plan of Reorganization that had been filed by the two CPUC commissioners who did not vote to approve the Settlement Agreement. These two commissioners have filed a notice of appeal of the District Court's order with the U.S. Court of Appeals for the Ninth Circuit. An appeal of the confirmation order filed by the City of Palo Alto remains pending at the District Court. PG&E Corporation and the Utility believe the appeals of the confirmation order are without merit.

In addition, on April 15, 2004, the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, each filed a petition with the California Court of Appeal seeking review of the CPUC's December 18, 2003 decision approving the Settlement Agreement and the CPUC's March 16, 2004 decision denying applications for rehearing of its December 18, 2003 decision. CCSF and Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF requests that the appellate court hear and review the CPUC's decisions, approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. Three California state senators have filed a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not yet acted on the petitions. PG&E Corporation and the Utility believe the petitions are without merit and should be denied.

Under applicable federal precedent, once the Plan of Reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this federal precedent, the bankruptcy court's confirmation order or the Settlement Agreement is subsequently overturned or modified, PG&E Corporation and the Utility's financial condition and results of operations could be materially adversely affected.

Financial Summary of the Settlement Agreement

In light of the satisfaction of various conditions to the implementation of the Plan of Reorganization, including the consummation of the public offering of the First Mortgage Bonds, the receipt of investment grade credit ratings, and final CPUC approval of the Settlement Agreement, the accounting probability standard required to be met under SFAS No. 71, in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement (as described below), was met as of March 31, 2004. Therefore, the Utility recorded the $2.2 billion, after-tax ($3.7 billion, pre-tax) Settlement Regulatory Asset, and $0.7 billion, after-tax ($1.2 billion, pre-tax), for the Utility retained generation regulatory assets, as summarized in the table below and discussed further in the paragraphs below:

(in millions)	Settlement Regulatory Asset		Utility Retained Generation Regulatory Assets		Total


Authorized, pre-tax, January 1, 2004	$	3,730	$	1,249	$	4,979
Amortization from January 1 to March 31, 2004	(58)		(21)		(79)

Recognition of regulatory assets, pre-tax, March 31, 2004	3,672		1,228		4,900
Deferred income taxes	(1,496)		(500)		(1,996)

Recognition of regulatory assets, after tax, March 31, 2004	2,176		728		2,904
Offsets of supplier settlements, after-tax	(8)		-		(8)

Net regulatory assets, after-tax, March 31, 2004	$	2,168	$	728	$	2,896

Settlement Regulatory Asset

The Settlement Agreement established a $2.2 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 the Utility's rate base that is being amortized on a "mortgage-style" basis over nine years beginning January 1, 2004. Under this amortization methodology, annual after-tax collections of the Settlement Regulatory Asset are estimated to range from approximately $140 million in 2004 to approximately $380 million in 2012. This after-tax Settlement Regulatory Asset is subject to reduction for any refunds, claim offsets, or other credits that the Utility receives from energy suppliers relating to specified electricity procurement costs incurred during the California energy crisis, including those arising from the settlement of CPUC litigation against El Paso Natural Gas Company. The Utility recognized a one-time non-cash gain of $3.7 billion, pre-tax, for the Settlement Regulatory Asset in th e first quarter of 2004. As discussed in Note 1, as of September 30, 2004, the Utility has recorded pre-tax offsets to the Settlement Regulatory Asset of approximately $300 million ($180 million after-tax) for supplier settlements and approximately $110 million ($65 million after-tax) for amortization of the Settlement Regulatory Asset.

The unamortized balance of the Settlement 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 the Utility's capital structure reaches 52%, the authorized equity component of the Settlement Regulatory Asset will be no less than 52% for the remaining term. If the Utility completes a refinancing of the Settlement Regulatory Asset supported by a dedicated rate component as discussed below, the equity and debt components of the Utility's rate of return will be replaced with the lower interest rate of the securitized debt.

Utility Retained Generation Regulatory Assets

In the Settlement Agreement, the CPUC deemed the Utility's adopted electricity generation rate base in a 2002 proceeding 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. Accordingly, the Utility recognized a one-time non-cash gain of $1.2 billion, pre-tax, for the retained generation regulatory assets in the first quarter of 2004. The individual components of the regulatory assets will be amortized over their respective lives, with a weighted average life of approximately 16 years. The Utility retained generation regulatory assets will earn an authorized rate of return on its equity component of 11.22% in 2004.

Ratemaking Matters

In the Settlement Agreement, the CPUC agreed to set the Utility's capital structure and authorized return on equity in its annual cost of capital proceedings in its usual manner. However, from January 1, 2004 until Moody's has issued an issuer rating for the Utility of not less than A3 or S&P has issued a long-term issuer credit rating for the Utility of not less than A-, the Utility's authorized return on equity will be no less than 11.22% per year and its authorized equity ratio for ratemaking purposes will be no less than 52%. However, for 2004 and 2005, the Utility's authorized equity ratio will be the greater of the proportion of equity approved in the Utility's 2004 and 2005 cost of capital proceedings, or 48.6%.

The CPUC also agreed to act promptly on certain of the Utility's pending ratemaking proceedings. The outcome of these proceedings may result in the establishment of additional regulatory assets on the Utility's Consolidated Balance Sheets.

Environmental Measures

·	In the Settlement Agreement, the Utility agreed to encumber with conservation easements or donate approximately 140,000 acres of land to public agencies or non-profit conservation organizations.
·	The Utility has established PG&E Environmental Enhancement Corporation as a California non-profit corporation to oversee the environmental enhancements associated with these lands. The Utility has agreed to fund the corporation with $100 million in cash over 10 years. In October 2004, the Utility paid the first installment of $10 million to this corporation. As of September 30, 2004, the Utility has recorded an $84 million liability based on the discounted present value of future cash payments to this corporation. The Utility will be entitled to recover these payments in rates. Therefore, the Utility recognized an offsetting regulatory asset and the recognition of the obligation had no impact on the Utility's results of operations.
·	The Utility has also established a California non-profit corporation that is dedicated to support research and investment in clean energy technology, primarily in the Utility's service territory. The Utility agreed to fund this corporation with $30 million payable over five years. In July 2004, the Utility made its first $2 million installment payment to this corporation. These contributions may not be recovered in rates. In the first quarter of 2004, the Utility recorded a $27 million pre-tax charge to earnings based on the discounted present value of future cash payments.

Of the approximately 140,000 acres referred to above, approximately 44,000 acres may be either donated or encumbered with conservation easements. The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and may only be encumbered with conservation easements. In the first quarter of 2004, the Utility recorded a $1 million pre-tax charge to earnings associated with the land donation obligation.

Fees and Expenses

The Settlement Agreement required the Utility 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. As of September 30, 2004, the Utility had a regulatory asset and associated liability of approximately $24 million relating to the CPUC reimbursable fees and expenses. Any changes to the final amount of the CPUC reimbursable fees and expenses will affect the regulatory asset and associated liability recorded by the Utility. In addition, one of the terms of the Settlement Agreement precluded the Utility from reimbursing PG&E Corporation for certain Chapter 11 related costs. As such, PG&E Corporation reduced its receivable from the Utility, and the Utility reduced its payable to PG&E Corporation, by $128 million. The transactions were recorded as a cont ribution of equity to the Utility by PG&E Corporation, net of taxes, and an increase to additional paid-in capital by the Utility in the first quarter 2004.

Refinancing Supported by a Dedicated Rate Component

Under the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized balance of the Settlement Regulatory Asset and related federal, state, and franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of the Plan of Reorganization using a securitized financing supported by a dedicated rate component, provided that certain conditions are met. In June 2004, the California Governor signed into law Senate Bill 772, which authorizes the issuance of Energy Recovery Bonds, or ERBs, to be secured by the establishment of a dedicated rate component to refinance the Settlement Regulatory Asset and related taxes. In addition to the authorizing legislation, the following other conditions must be met before a refinancing can occur:

·	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 Settlement Regulatory Asset;
·	The refinancing will not adversely affect the Utility's issuer or debt credit ratings; and
·	The Utility obtains, or decides it does not need, a private letter ruling from the Internal Revenue Service, or the IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

On June 8, 2004, the Utility filed a request for a private letter ruling with the IRS. It is expected that it will take up to six months for the IRS to conclude how it will respond to the request. Also, on July 22, 2004, the Utility filed an application with the CPUC requesting the authority to securitize the Settlement Regulatory Asset by issuing ERBs as discussed above, in an aggregate principal amount of up to $3.0 billion in two separate tranches up to one year apart. On October 19, 2004, the CPUC issued a proposed decision authorizing the issuance of the ERBs, subject to the approval of transaction terms by a financing team comprised of CPUC staff and their outside advisors. The CPUC used a similar financing team approach to approve the terms of the Utility's bankruptcy exit financing. Comments on the draft decision are due on November 8, and the Utility expects that the CPUC will issue a final decision by November 19, 2004. Assuming the timely satisfaction of these remaining conditions, the issuance of the first series of ERBs, in the amount of the after-tax balance of the Settlement Regulatory Asset (estimated to be approximately $1.8 billion), is targeted to occur in January 2005. Upon refinancing with securitization, the equity and debt components of the Utility's rate of return will be replaced with the lower interest rate of the securitized debt. The Utility would collect from customers amounts sufficient to service the principal and interest payments on the ERBs. The Utility would use the securitization proceeds to rebalance its capital structure in order to maintain the capital structure provided for under the Settlement Agreement.

Chapter 11 Claims

The following table summarizes the disposition of the net creditor claims made in the Utility's Chapter 11 proceeding, the amount of funds held in escrow for the resolution of disputed claims and the disputed claims accrued by the Utility at September 30, 2004:

(in billions)
Total filed claims in the Utility's Chapter 11 proceeding			$	51.7
ISO, PX and generator claims disallowed		(8.2)
Other claims disallowed by the bankruptcy court		(25.4)
Claims objected to by the Utility and pending before the bankruptcy court		(0.1)
Pass-through claims, including environmental, pending litigation and tort claims ⁽¹⁾		(4.7)
Principal payments made prior to the effectiveness of the Plan of Reorganization		(2.3)
Claims settled with the cancellation of bonds owned by the Utility		(0.3)
Payments on claims on and after the effectiveness of the Plan of Reorganization ⁽²⁾		(8.2)
Reinstated Pollution Control Bonds			(0.8)

Amount retained in escrow for remaining disputed claims - principal, at September 30, 2004			$	1.7
Disputed claims not accrued by the Utility				(0.1)

Net disputed claims accrued by the Utility at September 30, 2004			$	1.6






⁽¹⁾	The Utility has analyzed these claims and has recorded reserves for such claims that are included in the Utility's undiscounted environmental remediation liability of approximately $342 million at September 30, 2004 and the Utility's provision for legal matters of approximately $198 million at September 30, 2004, as discussed below in Note 6.
⁽²⁾	The Utility also made payments of approximately $0.2 billion for interest and bank premiums upon the effectiveness of the Plan of Reorganization.

As of September 30, 2004, the Utility had accrued approximately $1.6 billion for remaining disputed claims, consisting of approximately $2.1 billion of accounts payable-disputed claims primarily payable to the California Independent System Operator, or the ISO, and the Power Exchange, or the PX, offset by an accounts receivable amount from the ISO and the PX of approximately $0.5 billion. As disclosed in the table above, in connection with the implementation of the Plan of Reorganization, the Utility retained $1.7 billion in escrow for the payment of remaining disputed claims as of September 30, 2004. Although the Utility was required to retain $1.7 billion in escrow, the Utility does not believe it is probable that it will be found liable for approximately $0.1 billion of the $1.7 billion of the disputed claims and, therefore, in accordance with SFAS No. 5, "Accounting for Contingencies," or SFAS No. 5, the Utili ty has not recorded a liability in its financial statements for this amount.

NOTE 3: DEBT
Long-Term Debt

The following table summarizes PG&E Corporation's and the Utility's long-term debt that matures in one year or more from the date of issuance:

	Balance At

	September 30,		December 31,
(in millions)	2004		2003

PG&E Corporation
Senior secured notes, 6⅞ %, due 2008	$	600	$	600
Convertible subordinated notes, 9.50%, due 2010	280		280
Other long-term debt	2		3

Total long-term debt	882		883


Utility
First and refunding mortgage bonds:
5.85% to 8.80% bonds, maturing 2004-2026	-		2,764
Unamortized discount net of premium	-		(23)

Total first and refunding mortgage bonds	-		2,741
First mortgage bonds:
2.30% to 6.05% bonds, maturing 2006-2034	6,700		-
Unamortized discount, net of premium	(18)		-

Total first mortgage bonds	6,682		-
Pollution control loan agreements, variable rates, due 2007	614		-
Pollution control loan agreements, 5.35%, due 2016	200		-
Pollution control bond agreements, 3.50%, due 2023	345		-
Pollution control bond bridge facilities, variable rates, due 2005	454		-
Other	6		-
Less: current portion	(457)		(310)

Total long-term debt, net of current portion	7,844		2,431

Total consolidated long-term debt, net of current portion	$	8,726	$	3,314



Long-term debt subject to compromise:
Senior notes, 10.75%, due 2005	$	-	$	680
Pollution control loan agreements, variable rates, due 2026	-		614
Pollution control loan agreements, 5.35%, due 2016	-		200
Unsecured medium-term notes, 6.94% to 9.58%, due 2004-2014	-		287
Deferrable interest subordinated debentures, 7.90%, due 2025	-		300
Other	-		17

Total long-term debt subject to compromise	$	-	$	2,098

Utility

In March 2004, in connection with the implementation of the Plan of Reorganization, the Utility issued $6.7 billion of First Mortgage Bonds, or First Mortgage Bonds, and together with its consolidated subsidiaries, entered into $2.9 billion of credit facilities. The Utility obtained an interim $400 million cash collateralized letter of credit facility, which was terminated on April 12, 2004, the effective date of the Plan of Reorganization, or the Effective Date, and the letters of credit then outstanding were transferred to the $850 million revolving credit facility.

First Mortgage Bonds

On March 23, 2004, the Utility closed a public offering of $6.7 billion of First Mortgage Bonds. The First Mortgage Bonds were offered in multiple tranches consisting of 3.60% First Mortgage Bonds due March 1, 2009 in the principal amount of $600 million, 4.20% First Mortgage Bonds due March 1, 2011 in the principal amount of $500 million, 4.80% First Mortgage Bonds due March 1, 2014 in the principal amount of $1 billion, 6.05% First Mortgage Bonds due March 1, 2034 in the principal amount of $3 billion, and Floating Rate First Mortgage Bonds due April 3, 2006 in the principal amount of $1.6 billion. The Utility received proceeds of $6.7 billion from the offering, net of a discount of $18 million. The interest rate for the Floating Rate First Mortgage Bonds is based on the three-month London Interbank Offered Rate, or LIBOR, plus 0.70%, which resets quarterly. The next reset date is January 3, 2005.

In addition, approximately $2.5 billion of additional First Mortgage Bonds were issued on the Effective Date to various banks and insurance companies under the following agreements (1) the Utility's $620 million letters of credit backing pollution control bonds, (2) the Utility's reimbursement obligation under an insurance policy relating to $200 million in pollution control bonds that were issued for the benefit of the Utility, (3) the Utility's $345 million loan agreements with the California Pollution Control Financing Authority, or the CPCFA, (4) the Utility's $454 million reimbursement agreements for pollution control bond bridge facilities, and (5) the Utility's $850 million working capital facility.

On October 3, 2004, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $500 million.

The First Mortgage Bonds are secured by a first lien, subject to permitted exceptions, on substantially all of the Utility's real property and certain tangible personal property related to the Utility's facilities. Subject to certain conditions, the Utility will be entitled to terminate the lien and eliminate all terms and conditions relating to collateral for the First Mortgage Bonds on the release date. In general, the release date will occur when the Utility provides written evidence to the trustee of the First Mortgage Bonds that (1) the ratings on the Utility's long-term unsecured debt obligations following the release date would at least equal the initial ratings assigned by Moody's and S&P on the First Mortgage Bonds, or (2) comparable ratings by any other nationally recognized rating agency or agencies selected by the Utility if either Moody's or S&P do not then rate the Utility's long-term unsecure d debt obligations. The First Mortgage Bonds received initial investment grade credit ratings of Baa2 from Moody's and BBB from S&P.

If the lien securing the First Mortgage Bonds is released, the indenture will limit the ability of the Utility and its significant subsidiaries to incur secured debt and enter into sale and leaseback transactions.

Pollution Control Bonds
Variable Rate and 5.35% Pollution Control Loan Agreements

Under pollution control loan agreements, the Utility is obligated to reimburse the CPCFA for funds received by the Utility from the issuance of the CPCFA's pollution control bonds for the benefit of the Utility. The principal amount of these loan obligations totaled $814 million at September 30, 2004. Interest rates on $614 million of $814 million of the obligations are variable. As of September 30, 2004, the variable interest rates ranged from 1.35% to 1.38%. The interest rate on the remaining $200 million of the obligations is fixed at 5.35%.

The CPCFA pollution control bonds in the principal amount of $200 million, bearing interest at a fixed rate, are backed by bond insurance. The CPCFA pollution control bonds in the principal amount of $614 million, bearing interest at variable rates, are backed by letters of credit of $620 million. The Utility's reimbursement obligations are supported by $820 million in First Mortgage Bonds that have been issued to the bond insurer and letter of credit banks.

Drawings for interest due under the loan agreements are made under these letters of credit on each scheduled interest payment date, which is the first business day of each month. On the same day, the Utility pays the amount of the draw to the letter of credit banks per terms of the reimbursement agreements. The letters of credit are then reinstated to the full amount of their initial commitments.

Pollution Control Bond Terms Loan Facility and 3.5% Pollution Control Bonds Loan Agreements

On the Effective Date, the Utility entered into a $345 million term loan facility that was used to fund the Utility's purchase, in lieu of redemption, of the CPCFA's Pollution Control Revenue Bonds, 1992 Series A and B and 1993 Series A and B, or collectively the Old Bonds.

On June 29, 2004, the Utility entered into four separate loan agreements, each dated as of June 1, 2004, with the CPCFA, which issued $345 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds, 2004 Series A ($70 million), 2004 Series B ($90 million), 2004 Series C ($85 million) and 2004 Series D ($100 million), or collectively the New Bonds, to refund the Old Bonds held by the Utility. The funds made available from the refund of Old Bonds were used to repay the $345 million term loan facility. Principal and interest payments on the New Bonds are backed by bond insurance and the Utility's obligations under the new loan agreements are supported by $345 million of First Mortgage Bonds that are held by the trustee for the New Bonds. The New Bonds must be purchased from their holders on June 1, 2007.

Pollution Control Bond Bridge Facilities

During the Utility's Chapter 11 proceeding, approximately $454 million in aggregate principal amount of pollution control bonds, which were issued for the Utility's benefit and were credit enhanced with letters of credit were redeemed through draws on the letters of credit. On the Effective Date, the Utility executed bridge loans with new lenders who had purchased the $454 million reimbursement obligations owed by the Utility to the letter of credit issuers and entered into four separate amended and restated reimbursement agreements with the new lenders. The Utility intends to refinance the $454 million with long-term tax-exempt bonds or taxable debt. The outstanding balance of $454 million at September 30, 2004 under the amended and restated reimbursement agreements is due and payable on June 5, 2005. At the Utility's request and at the sole discretion of each lender, each amended and restated reimbursement agreement may be extended for additional periods. On the Effective Date, the Utility supported its obligations under the amended and restated reimbursement agreement with $454 million of First Mortgage Bonds.

Repayment Schedule

The following table details the scheduled maturities of the Utility's long-term debt outstanding at September 30, 2004:

(in millions)	2004		2005		2006		2007		2008		Thereafter		Total


Long-term debt:
Average fixed interest rate	7.40%		-		-		3.50%		-		5.34%		5.22%
Fixed rate obligations	$	1	$	-	$	-	$	345	$	-	$	5,282	$	5,628
Variable interest rate as of September 30, 2004		-		2.85%		2.30%	1.35-1.38%			-		-		-
Variable rate obligations	-		454		1,600		614		-		-		2,668
Other	1		2		2		-		-		-		5

Total	$	2	$	456	$	1,602	$	959	$	-	$	5,282	$	8,301

Credit Facilities and Short-Term Borrowings

The following table summarizes the Utility's outstanding credit facilities and short-term borrowings subject to compromise at December 31, 2003, which were paid and cancelled on the Effective Date. At September 30, 2004, the Utility and its consolidated subsidiaries did not have any outstanding balances on any of its credit facilities. At September 30, 2004, PG&E Corporation did not maintain any credit facilities or have any short-term borrowings. The Utility's and its consolidated subsidiaries' credit facilities and agreements consist of the following:

(in millions)
	September 30, 2004				December 31, 2003

Credit facilities:	Revolving Credit Limit		Outstanding		Outstanding

Accounts receivable financing	$	650	$	-	$			-
Working capital facility	850			-	-

Total credit facilities	$	1,500	$	-	$		-




Credit facilities subject to compromise:
5-year revolving credit facility	$	-	$	-		$	938

Total credit facilities subject to compromise	$	-	$	-	$		938

Short-term borrowings subject to compromise
Bank borrowings - drawn letters of credit for accelerated pollution control agreement	$	-	$	-	$		454
Floating rate notes	-			-	1,240
Commercial paper	-			-	873

Total credit facilities and short-term borrowings subject to compromise	$	-	$	-	$		3,505

		September 30, 2004

Letters of Credit ⁽¹⁾:
Pollution control bonds reimbursement agreements		$	620
Working capital facility		163

		$	783



First Mortgage Bonds issued to secure and support various debt and credit facilities ⁽¹⁾:
Pollution control loan agreements, variable rates, due 2007		$	620
Pollution control loan agreements, 5.35%, due 2006		200
Pollution control bond agreements, 3.50% variable, due 2023		345
Pollution control bond bridge facilities, variable rates, due 2005		454
Working capital facility		850

		$	2,469






⁽¹⁾	Off-balance sheet commitments.

Accounts Receivable Financing

On March 5, 2004, the Utility entered into certain agreements providing for the continuous sale of a portion of the Utility's accounts receivable to PG&E Accounts Receivable Company, LLC, or PG&E ARC, a limited liability company wholly owned by the Utility. In turn, PG&E ARC sells interests in its accounts receivable to commercial paper conduits or banks. PG&E ARC may obtain up to $650 million of financing under such agreements. The borrowings under this facility bear interest at commercial paper rates and a fixed margin based on the Utility's credit ratings. Interest on the facility is payable monthly. The maximum amount available for borrowing under this facility changes based upon the amount of eligible receivables, concentration of eligible receivables and other factors. Unless extended, the credit facility will terminate on March 5, 2007. The credit facility may be extended for additional periods upon the agreement of all parties. The Utility began selling accounts receivables to PG&E ARC on the Effective Date and used the proceeds from the sale of the accounts receivable in connection with this credit facility to pay allowed claims on the Effective Date. On May 7, 2004, PG&E ARC paid off this credit facility, and on September 30, 2004, there were no amounts drawn on the credit facility. Although PG&E ARC is a wholly owned consolidated subsidiary of the Utility, PG&E ARC is legally separate from the Utility. The assets of PG&E ARC (including the accounts receivable) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivable are not legally assets of the Utility or PG&E Corporation. For the purposes of financial reporting, the credit facility is accounted for as a secured financing.

The accounts receivable facility includes a covenant from the Utility requiring it to maintain, as of the end of each fiscal quarter ending after the Effective Date, a debt to capitalization ratio of at most 0.65 to 1.00.

Working Capital Facility

On March 5, 2004, the Utility entered into an $850 million revolving credit facility, or working capital facility, with a syndicate of banks. Loans under the working capital facility will be used primarily to cover operating expenses and seasonal fluctuations in cash flows. Letters of credit under the working capital facility will be used primarily to provide credit enhancements to counterparties for natural gas and electricity procurement transactions. The working capital facility has a term of three years and all outstanding amounts will be due and payable on March 5, 2007. At the Utility's request and at the sole discretion of each lender, the working capital facility may be extended for additional periods. On the Effective Date, the Utility supported its obligation under the working capital facility with First Mortgage Bonds. There were no loans outstanding under the working capital facility at September 30 , 2004. However, the Utility had approximately $163 million of letters of credit outstanding.

The working capital facility includes covenants requiring:

·	Maintenance, as of the end of each fiscal quarter ending after the Effective Date, of a debt to capitalization ratio of at most 0.65 to 1.00; and
·	Until the lien securing the First Mortgage Bonds is released, a limitation on liens other than those specifically permitted by the indenture for the First Mortgage Bonds. As noted above, after the release of the lien, the First Mortgage Bonds indenture then limits the ability of the Utility and its significant subsidiaries to incur secured debt and enter into sale and leaseback transactions.

Cash Collateralized Letter of Credit

On March 2, 2004, the Utility entered into a cash collateralized $400 million letter of credit facility that was used to issue letters of credit to provide credit support in connection with the Utility's pre-existing and new natural gas procurement activities and related purchases of natural gas transportation services. As discussed above, this credit facility was terminated on the Effective Date, and the outstanding balance of letters of credit was transferred to the $850 million working capital facility.

PG&E Corporation
Convertible Subordinated Notes

PG&E Corporation currently has outstanding $280 million of 9.50% Convertible Notes that are scheduled to mature on June 30, 2010. These Convertible Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,655 shares of common stock of PG&E Corporation, at a conversion price of $15.09 per share. The conversion price is subject to adjustment should a significant change occur in the number of PG&E Corporation's outstanding common shares. To date, the conversion price has not required adjustment. In addition, the terms of the Convertible Notes entitle the note holders to participate in any dividends declared and paid on PG&E Corporation's common shares based on their equity conversion value.

In accordance with SFAS No. 133, the dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be bifurcated from the Convertible Notes and marked to market on PG&E Corporation's Consolidated Statements of Income as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation's Consolidated Balance Sheets as a non-current liability (in Non-current liabilities - other). At September 30, 2004, the estimated fair value of the dividend participation rights component was approximately $70 million, an increase in value of approximately $3 million, net of taxes, from June 30, 2004, and a year-to-date increase of approximately $41 million, net of taxes, for the nine-month period ended September 30, 2004.

Senior Secured Notes

PG&E Corporation currently has outstanding $600 million of 6⅞% Senior Secured Notes due July 15, 2008, or Senior Secured Notes. The Senior Secured Notes are secured by a perfected first-priority security interest in approximately 94% of the outstanding common stock of the Utility that is owned by PG&E Corporation. On October 14, 2004, PG&E Corporation notified the trustee of its decision to redeem the Senior Secured Notes in full. On October 15, 2004, the trustee sent a notice to all holders that the Senior Secured Notes would be redeemed in full on November 15, 2004. Redemption of the Senior Secured Notes will require approximately $664.5 million of PG&E Corporation's cash, which includes a redemption premium of approximately $50.7 million and $13.8 million of interest that has accrued since the last interest payment date. As a result of the Senior Secured Note redemption, PG&E C orporation will write off $14.6 million of unamortized loan fees.

NOTE 4: DISCONTINUED OPERATIONS

Effective July 8, 2003 (the date NEGT filed a voluntary petition for relief under Chapter 11), NEGT and its subsidiaries are no longer consolidated by PG&E Corporation in its Consolidated Financial Statements. Under GAAP, consolidation is generally required for entities owning more than 50% of the outstanding voting stock of an investee, except when control is not held by the majority owner. Legal reorganization and bankruptcy represent conditions that can preclude consolidation in instances where control rests with an entity other than the majority owner. In anticipation of NEGT's Chapter 11 filing, PG&E Corporation's representatives who previously served on the NEGT Board of Directors resigned on July 7, 2003, and were replaced with Board members who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retained significant influence over the ongoing operations of NEG T.

Accordingly, PG&E Corporation's negative investment in NEGT of approximately $1.2 billion is reflected as a single amount, under the cost method, within the September 30, 2004 Consolidated Balance Sheets of PG&E Corporation. This negative investment represents the losses of NEGT recognized by PG&E Corporation in excess of its investment in and advances to NEGT. Furthermore, at September 30, 2004, the Consolidated Balance Sheet includes a net deferred tax asset of approximately $432 million, a current tax liability of approximately $145 million, other net liabilities of approximately $28 million and a charge of approximately $77 million, net of tax, in accumulated other comprehensive income, related to NEGT.

On October 29, 2004, NEGT's plan of reorganization became effective, at which time NEGT emerged from Chapter 11 and PG&E Corporation's equity ownership in NEGT was cancelled. On the effective date, PG&E Corporation reversed its negative investment in NEGT and also reversed NEGT-related deferred income tax assets and accumulated other comprehensive income. The resulting net gain has been offset by the $30 million payment made by PG&E Corporation to NEGT pursuant to the parties' settlement of certain tax-related litigation (See Note 6, Commitments and Contingencies). A summary of the approximate effect on earnings from discontinued operations is as follows:

(in millions)
Investment in NEGT	$	1,211
Accumulated other comprehensive income	(120)
Cash paid pursuant to settlement of tax related litigation	(30)
Tax Effect	(381)

Gain on disposal of NEGT, net of tax	$	680

Subsequent to the cancellation of its equity interest, at October 29, 2004, PG&E Corporation's Consolidated Balance Sheet includes $166 million in income tax and other net liabilities related to NEGT. Beginning on the effective date of NEGT's plan of reorganization, PG&E Corporation will no longer include NEGT or its subsidiaries in its consolidated income tax returns.

NEGT Operating Results

Included within earnings from discontinued operations on the Consolidated Statements of Income of PG&E Corporation are NEGT's operating results, summarized below:

		188 days ended
(in millions)		July 7, 2003


Operating revenues ⁽¹⁾		$	786
Loss before income taxes ⁽¹⁾		(595)
Net income ⁽¹⁾		(370)



⁽¹⁾	Amounts shown have been adjusted for intercompany eliminations.

Prior to July 8, 2003, NEGT had accounted for certain of its subsidiaries as discontinued operations. The operating results shown above reflect the operating results of USGen New England, Inc. through September 30, 2003 and the other previously discontinued operations through the respective disposal dates. The pre-tax loss of NEGT and its subsidiaries for the nine months ended September 30, 2003 includes the following gains and losses on disposal of those subsidiaries: a pre-tax loss of approximately $14 million on disposal of certain Ohio generating plants, a pre-tax gain of approximately $19 million on disposal related to the sale of Mountain View Power Partners, LLC in January 2003, and an additional pre-tax loss of approximately $3 million on disposal related to the sale of PG&E Energy Trading, Canada Corporation in the first quarter of 2003.

In 2003, PG&E Corporation increased its valuation allowance against certain state deferred tax assets related to NEGT and its subsidiaries due to the uncertainty of their realization. Valuation allowances of approximately $24 million were recorded in discontinued operations and approximately $5 million was recorded in accumulated other comprehensive loss for the nine-month period ended September 30, 2003. No similar amounts were recorded in the three-month period ended September 30, 2003 or during 2004.

NOTE 5: PRICE RISK MANAGEMENT

As discussed in Note 4, NEGT financial results are no longer consolidated with those of PG&E Corporation following the July 8, 2003 Chapter 11 filing of NEGT. NEGT's financial results through July 7, 2003 are reflected in discontinued operations. Because NEGT financial results are no longer consolidated with those of PG&E Corporation, the only risk management activities currently reported by PG&E Corporation are related to Utility non-trading activities, which are executed on a non-trading basis.

Non-Trading Activities

At September 30, 2004, the Utility had cash flow hedges associated with its natural gas commodity price risk. These cash flow hedges are presented at fair value of $5 million in other current assets on the Utility's Consolidated Balance Sheets. At December 31, 2003, the Utility had cash flow hedges associated with natural gas commodity price risk that are presented at fair value of $4 million in other current assets. These hedges are associated with regulated operations. Therefore, the effective and ineffective portions are recoverable through regulated rates, and are recorded on the balance sheet in regulatory accounts.

The Utility has certain contracts for the purchase of electricity, natural gas transportation and storage, and nuclear fuel that are either exempt from the SFAS No. 133 fair value requirements under the scope exceptions or are not derivative instruments and, therefore, have no mark-to-market effect on earnings. Additionally, the Utility holds derivative instruments that do not qualify for cash flow hedge accounting or the scope exceptions to SFAS No. 133. At September 30, 2004, the fair value of $9 million is recorded in other current assets and $3 million is recorded in other current liabilities. The costs of these derivatives are recovered through regulated rates charged to customers and the Utility records the offset to the regulatory accounts.

Credit Risk

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if customers or counterparties failed to perform their contractual obligations.

PG&E Corporation had gross accounts receivable of approximately $2.0 billion at September 30, 2004 and approximately $2.5 billion at December 31, 2003. The majority of the accounts receivable are associated with the Utility's residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately $63 million at September 30, 2004 and approximately $68 million at December 31, 2003 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. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance f rom these customers is not considered likely.

The Utility manages credit risk for its wholesale 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 the Utility's wholesale customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure, which could include obtaining additional collateral, or both. Further, the Utility relies 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.

The Utility calculates gross credit exposure for each of its wholesale 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 the first nine months of 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At September 30, 2004, there were two counterparties that represented greater than 10% of the Utility's net wholesale credit exposure. These two investment grade counterparties represented a total of approximately 46% of the Utility's net wholesale credit exposure.

The Utility conducts business with wholesale counterparties 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 the Utility's overall exposure to credit risk because counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions.

The schedule below summarizes the Utility's net asset credit risk exposure, as well as the Utility's credit risk exposure to its wholesale customers or counterparties with a greater than 10% net credit exposure, at September 30, 2004 and December 31, 2003.

(in millions)		Gross Credit Exposure Before Credit Collateral ⁽¹⁾		Credit Collateral		Net Credit Exposure ⁽²⁾		Number of Wholesale Customers or Counterparties >10%		Net Exposure to Wholesale Customers or Counterparties >10%


September 30, 2004		$	108	$	13	$	95		2		$	43
December 31, 2003		165		11		154		3		68



⁽¹⁾	Gross credit exposure equals mark-to-market value, notes receivable and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity or credit reserves. The Utility's gross credit exposure includes wholesale activity only. Retail activity and payables are not included. Retail activity at the Utility consists of the accounts receivable from the sale of natural gas and electricity to residential and small commercial customers.
⁽²⁾	Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

The schedule below summarizes the credit quality of the Utility's net credit risk exposure to the Utility's wholesale customers and counterparties at September 30, 2004 and December 31, 2003:

(in millions)		Net Credit Exposure ⁽²⁾		Percentage of Net Credit Exposure


Credit Quality ⁽¹⁾
September 30, 2004
Investment grade ⁽³⁾		$	92	97%
Non-investment grade		3		3%

Total		$	95	100%




December 31, 2003
Investment grade ⁽³⁾		$	108	70%
Non-investment grade		46		30%

Total		$	154	100%






⁽¹⁾	Credit ratings are determined by using publicly available information. If provided a guarantee by a higher rated entity (e.g., an affiliate), the rating is determined based on the rating of the guarantor.
⁽²⁾	Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.
⁽³⁾	Investment grade is determined using publicly available information, i.e., rated at least Baa3 by Moody's and BBB- by S&P. The Utility has assessed certain governmental authorities that are not rated through publicly available information as investment grade based upon an internal assessment of credit worthiness.

NOTE 6: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments and contingencies in connection with agreements entered into to support the Utility's operating activities. The following summarizes PG&E Corporation's and the Utility's material contingencies and cancelled, new, and significantly modified commitments since the Current Report on Form 8-K dated June 18, 2004 (which supercedes the information included in the combined 2003 Annual Report).

Commitments
Utility
Power Purchase Agreements

During the nine-month period ended September 30, 2004, the Utility entered into various agreements to purchase energy. Under these agreements, the Utility is committed to make energy payments of approximately $159 million and capacity payments of approximately $6 million in 2004.

Natural Gas Supply and Transportation Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers. The contract lengths and natural gas sources of the Utility's portfolio of natural gas procurement contracts have fluctuated generally based on market conditions.

During the period that the Utility was in Chapter 11, the Utility used several different credit arrangements to purchase natural gas, including a $10 million cash collateralized standby letter of credit and a pledge of its core natural gas customer accounts receivable. In connection with its emergence from Chapter 11, the Utility received investment grade issuer credit ratings from Moody's and S&P. As a result of these credit rating upgrades, the Utility has obtained unsecured credit lines from the majority of its gas supply counterparties.

At September 30, 2004, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

(in millions)

2004	$	371
2005	714
2006	26
2007	7
2008	-
Thereafter	-

Total	$	1,118

Nuclear Fuel Agreements

The Utility has purchase agreements for nuclear fuel. These agreements have terms ranging from two to eight years and are intended to ensure long-term fuel supply. Deliveries under 9 of the 11 contracts in place at the end of 2003 will be completed by 2005. New contracts for deliveries in 2005 to 2012 are under negotiation. In most cases, the Utility's nuclear fuel contracts are requirements-based. The Utility relies on large, well-established international producers of nuclear fuel in order to diversify its commitments and provide security of supply. Pricing terms also are diversified, ranging from fixed prices to market-based prices to base prices that are escalated using published indices.

At September 30, 2004, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)

2004	$	128
2005	28
2006	29
2007	38
2008	30
Thereafter	64

Total	$	317

Transmission Control Agreement

The Utility has entered into a Transmission Control Agreement, or TCA, with the ISO and other participating transmission owners (including Southern California Edison, or SCE, San Diego Gas & Electric Company, and several municipal utilities) under which the transmission owners have assigned operational control of their electricity transmission systems to the ISO. The Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA.

The ISO also has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require certain power plants, known as RMR plants, to remain available to generate electricity upon the ISO's demand when needed for local transmission system reliability. As a party to the TCA, the Utility is responsible for a share of the ISO's costs paid to power plant owners under RMR agreements within the Utility's service territory.

At September 30, 2004, the Utility estimated that it could be obligated to pay the ISO approximately $605 million in costs incurred under these RMR agreements during the period October 1, 2004 to September 30, 2006. Of this amount, the Utility estimates that it would receive approximately $96 million under its RMR agreements during the same period. These costs and revenues are subject to applicable ratemaking mechanisms.

It is possible that the Utility may receive a refund of RMR costs that the Utility previously paid to the ISO. In June 2000, a FERC administrative law judge, or ALJ, issued an initial decision in a rate case filed by subsidiaries of Mirant Corporation, or Mirant, approving rates and a ratemaking methodology that, if affirmed by the FERC, would require the subsidiaries of Mirant that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $350 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, the Utility filed claims in Mirant's Chapter 11 proceeding including a claim for an RMR refund. The Utility is unable to predict at this time when the FERC will issue a final decision in Mirant's c ase, what the FERC's decision will be, the amount of any refunds the Utility may ultimately receive, and how the resolution of this matter would be reflected in the rates. Due to this uncertainty as of September 30, 2004, the Utility had not recorded any amounts in its Consolidated Balance Sheet for any refunds receivable that may result from the FERC's final decision.

In November 2001, after the ALJ issued the initial decision in Mirant's rate case, various complaints were filed at the FERC against other RMR plant owners, including the Utility, alleging that the ratemaking methodology approved in the ALJ's initial decision should be applied to the other RMR plant owners. If the FERC adopts the ALJ's decision in the Mirant rate case and applies the ratemaking methodology to the Utility's RMR plants, the Utility could be required to refund payments it received from the ISO for the availability of the Utility's RMR plants. The Utility has responded to the complaint asserting that the methodology approved in the ALJ's decision should not apply to the Utility. The FERC has not yet acted on these complaints. The Utility believes the ultimate outcome of this matter will not have an adverse material effect on the Utility's results of operations or financial condition.

WAPA Commitments

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

On October 15, 2004, the Utility filed Offers of Settlement with the FERC to terminate the FERC rate schedules associated with the 1967 WAPA contracts. The Offers of Settlement were signed by the Utility and WAPA, and in one instance by the California ISO as operator of much of the Utility's transmission system. The Offers of Settlement, if accepted by the FERC as filed, will terminate the rate schedules associated with the 1967 contracts on January 1, 2005, and will replace them with new service contracts under which the Utility no longer will provide any electric power or transmission services but will continue to provide wholesale distribution service. The new service contracts were filed on October 21, 2004. There is no monetary component to the Offers of Settlement; their purpose is to terminate the 1967 contracts and to replace them. The Utility's cost obligations associated with the 19 67 contracts will terminate with those contracts and related FERC rate schedules and will not be replaced.

It is possible that the FERC will not accept the Offers of Settlement as filed or will materially alter them or suspend their effectiveness beyond January 1, 2005. The costs to fulfill the Utility's obligations to WAPA under the contracts cannot be accurately estimated at this time since both the purchase price and the amount of electric power that WAPA will need from the Utility in 2005 are uncertain. However, the Utility expects that the cost of meeting its contractual obligations to WAPA will be greater than the price the Utility receives from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, the Utility's estimated net costs, based upon its portfolio and after subtracting revenues received from WAPA, for electricity delivered under the contracts were approximately $57 million and $161 million in the three and nine-month periods ended September 30, 2004.

Other Commitments

The Utility has other commitments relating to operating leases, capital infusion agreements, equipment replacements, software licenses, the self-generation incentive program exchange agreements and telecommunication contracts. At September 30, 2004, the future minimum payments related to other commitments were as follows:

(in millions)

2004	$	97
2005	95
2006	32
2007	17
2008	14
Thereafter	5

Total	$	260

Contingencies

The Utility has significant gain and loss contingencies, which are discussed below.

2003 General Rate Case

In May 2004, the CPUC issued a decision in the Utility's 2003 GRC. The 2003 GRC determines the amount the Utility can collect from customers, or base revenue requirements, to recover its basic business and operational costs for electricity and natural gas distribution operations and for electricity generation operations for 2003 and certain succeeding years.

The decision approved the July 2003 and September 2003 settlement agreements reached among the Utility and various consumer groups to set the Utility's 2003 base revenue requirements at approximately:

·	$2.5 billion for electricity distribution operations, representing a $236 million increase over the previously authorized amount;
·	$912 million for electricity generation operations, representing a $38 million increase over the previously authorized amount; and
·	$927 million for natural gas distribution operations, representing a $52 million increase over the previously authorized amount.

As part of the GRC, the CPUC approved the following minimum and maximum yearly adjustments to the Utility's 2003 base revenue requirements, or attrition rate adjustments, for 2004, 2005, and 2006 based on the change in the Consumer's Price Index, or CPI:

	2004	2005	2006

Electricity and Natural Gas Distribution
Minimum	2.00%	2.25%	3.00%
Multiplier	Change in CPI	Change in CPI	Change in CPI+1%
Maximum	3.00%	3.25%	4.00%

Electricity Generation
Minimum	1.50%	1.50%	2.50%
Multiplier	Change in CPI	Change in CPI	Change in CPI+1%
Maximum	3.00%	3.00%	4.00%

In addition, under the GRC decision, if the Utility forecasts a second refueling outage at Diablo Canyon in any one year, the electricity generation revenue requirement would be increased to reflect a fixed revenue requirement of $32 million per refueling outage, adjusted for changes in the CPI in the manner described in the decision. Currently, the only forecasted second refueling outage will occur in 2004.

As a result of the approval of the 2003 GRC, during the second quarter of 2004, the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets and unfunded taxes, depreciation, and decommissioning. During the third quarter of 2004, the Utility recorded electricity and natural gas distribution and electricity generation revenues under the new revenue requirements as approved by the 2003 GRC. The net impact of the items which were recorded in the second quarter, on a pre-tax basis is as follows:

					Amount Previously Recorded in 2003

	Impact Related to						Net 2004 Adjustment

(in millions)	2003		2004


Electricity revenue	$	273	$	152	$	268	$	157
Natural gas revenue	52		25		-		77
Electricity attrition	-		48		-		48
Natural gas attrition	-		9		-		9
Regulatory assets, net	(17)		158		-		141

Total	$	308	$	392	$	268	$	432

Because the Utility collected revenue subject to refund for electricity distribution and generation in 2003, but not for natural gas distribution, the impact of the 2003 GRC decision on the Utility's 2004 results of operations is different for each area.

For electricity distribution and generation, the Utility collected electricity revenue and surcharges subject to refund under the frozen rate structure in 2003. The amount of electricity revenue to be refunded in 2003 incorporated the impact of the electric portion of the GRC settlement and was recorded as a regulatory liability at December 31, 2003. In 2004, the Utility recorded its electricity distribution and generation base revenue requirements under a cost of service ratemaking structure. Because the 2003 refund obligation already incorporated the impact of the GRC that related to fiscal 2003, and since the CPUC issued a final decision approving a revenue requirement increase in 2004, the Utility recorded the increase related to the six-month period ended June 30, 2004 in its 2004 results of operations of approximately $157 million.

For natural gas distribution, since the CPUC issued a final decision on the Utility's 2003 GRC in 2004, the Utility recorded both the 2003 revenue requirement increase and the 2004 revenue requirement increase related to the six-month period ended June 30, 2004 in its 2004 results of operations of approximately $77 million.

The total attrition adjustment for 2004 is approximately $127 million (consisting of $82 million for base revenue requirements, $32 million allowance for a second refueling outage in 2004 at Diablo Canyon and $13 million for public purpose program expenses) based on the minimum attrition adjustments. The CPUC approved the Utility's attrition requests in July 2004. The Utility recorded the increase related to attrition for the six-month period ended June 30, 2004, in its results of operations of approximately $57 million.

In addition, as a result of the GRC decision, the Utility has recorded various regulatory assets and liabilities associated with the recovery of retained generation assets, unfunded taxes, depreciation, and decommissioning. The net impact of these items resulted in after-tax earnings of approximately $84 million recorded in the Utility's 2004 results of operations. These assets and liabilities are reflected in the Utility's current rates and will be amortized over their respective collection periods.

Another phase of the GRC was established to address the Utility's response to the December 2002 storm and the Utility's reliability performance. In October 2004, the CPUC voted to approve certain storm response improvement initiatives as well as a reliability performance incentive mechanism for the years 2005 through 2007. Under the performance incentive mechanism the Utility could receive up to $24 million each year depending on the extent to which the Utility exceeds the reliability performance improvement targets, but could be required to pay a penalty of up to $24 million a year depending on the extent to which it fails to meet the targets. The decision does not provide the Utility with additional revenues to meet the reliability standards, but does include a wide margin of error around the targets in order to mitigate potential penalties. PG&E Corporation and the Utility are unable to predict whether or not the Utility will incur a reward or penalty related to the performance incentive mechanism.

PX Block-Forward Contract

The Utility had PX block-forward contracts, which were seized by California's then-Governor Gray Davis in February 2001 for the benefit of the state, acting under California's Emergency Services Act. The block-forward contracts had an estimated unrealized gain of up to $243 million at the time the state of California seized them. The Utility, the PX, and some of the PX market participants have filed claims in state court against the state of California to recover the value of the seized contracts; the state of California disputes the plaintiffs' rights to recover and valuations. The estimated value of the seized contracts has been fully reserved in the Utility's financial statements. This state court litigation is pending.

Nuclear Insurance

The Utility has several types of nuclear insurance for Diablo Canyon and Humboldt Bay Unit 3. The Utility has 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 incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay additional premiums of up to $42.5 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 $10.8 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for Diablo Canyon. The balance of the $10.8 billion of liability protection is covered by a loss-sharing program (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 megawatts, or MW, or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility 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 the Utility has fully paid its share of the liability. Since Diablo Canyon has two nuclear reactors over 100 MW, the Utility 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 Diablo Canyon, which had coverage before December 31, 2003. Congress may address renewal of the Price-Anderson Act in future energy legislation.

In addition, the Utility has $53.3 million of liability insurance for the retired nuclear generating unit at Humboldt Bay power plant and has a $500 million indemnification from the NRC, for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

Workers' Compensation Security

The Utility is self-insured for workers' compensation. To maintain its status as a self-insurer for workers' compensation, the Utility must either deposit collateral with the California Department of Industrial Relations, or the DIR, or participate in the Alternative Security Deposit program, or the ASP, which is administered by the Self-Insurer's Security Fund, or the SISF. The ASP is a program that allows the SISF to arrange a composite deposit for participating self-insurers on a portfolio basis, rather than individual self-insurers arranging their deposits individually. The SISF arranges portfolio security to be delivered to the DIR for the aggregate self-insured workers' compensation liabilities for participating self-insurers. The SISF composite deposit for participating self-insurers, including the Utility, was established on July 1, 2004, and resulted in the release of the $348 million collateral ($305 mi llion in surety bonds and $43 million in cash) that existed at June 30, 2004. As a result, PG&E Corporation's guarantee of the Utility's reimbursement obligation associated with these surety bonds was also released on July 1, 2004.

PG&E Corporation's guarantee of the Utility's underlying obligation to pay workers' compensation claims remains in place. As of September 30, 2004, the actuarially determined workers' compensation liability was approximately $225 million (discounted).

California Energy Crisis Proceedings

FERC Proceedings

Various entities, including the Utility and the state of California are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers from January 2000 to June 2001 through a proceeding pending at the FERC. This FERC proceeding, the "Refund Proceeding," commenced on August 2, 2000 when a complaint was filed against all suppliers in the ISO and PX markets. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the amount of the overcharges that will be refunded. The FERC asserted that it would not order refunds for periods before October 2, 2000, because under a federal statute it can only order refunds beginning 60 days after a complaint for overcharges was filed and the first complaint for overcharges was not filed with the FERC until August 2, 2000. In December 2002, a FERC ALJ issued an initial decision in the Refund Proceeding 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, but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

In March 2003, the FERC confirmed most of the ALJ's findings in the Refund Proceeding, 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 the first quarter of 2005. The PX cannot make its compliance filing until after the ISO has made its filing. In October 2003, the FERC affirmed its March 2003 decision. Various parties have filed appeals with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, of the various FERC orders in the Refund Proceeding. Although the Ninth Circuit originally held those appeals in abeyance while the FERC process continued, on October 22, 2004, the Ninth Circuit ordered that the appeals should proceed. According to a schedule being developed by the Ninth Circuit, the parties are required to submit briefs by March 2005 to address the issues of which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds.

The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings and the resolution of the appeals of the FERC's orders. The FERC is uncertain when it will issue a final decision in the Refund Proceeding, after which appellate review is expected. In addition, future refunds could increase or decrease as a result of retroactive adjustments proposed by the ISO, which incorporate revised data provided by the Utility and other entities.

As noted above, the FERC asserted in the Refund Proceeding that it does not have the power to direct the power suppliers to make comprehensive market-wide refunds to ratepayers for the period before October 2, 2000. However, in the FERC's separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, the FERC has asserted that it has the power to order power suppliers to disgorge any profits if the FERC finds that the tariffs in force at that time were violated or subject to manipulation. In addition, in September 2004, acting in a separate case from the Refund Proceeding and the FERC's investigative proceedings, the Ninth Circuit found that the FERC has the authority to provide refunds for tariff violations involving inadequate transaction reporting for sales into the California spot markets throughout the period before October 2, 2000. The Ninth Circuit remanded the case to the FERC to determine the appropriate remedy. Pending a decision on the suppliers' request for a rehearing of this Ninth Circuit decision, the FERC has not yet acted on the September 2004 remand order. It is uncertain whether the Ninth Circuit's decision interpreting the FERC's power to order refunds will be upheld and how it will be applied by the FERC.

The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its 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. Under a bankruptcy court order, the aggregate allowable amount of ISO, PX and generator claims was limited to approximately $1.6 billion. The Utility currently estimates that the claims would have been reduced to approximately $1.0 billion based on the refund methodology recommended in the FERC ALJ's initial decision. The recalculation of market prices according to the revised methodology adopted by the FERC in its March 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. The FERC has directed that sellers claiming a fuel cost allowance should submit their claims to an independent auditor before inclusion of any amounts in an ISO calculation of refunds and offsets for such fuel costs.

The Utility has entered into various settlements with power suppliers resolving the Utility's claims against these power suppliers. Although settlement discussions with a number of other major sellers and other market participants are continuing, the Utility cannot predict whether these settlement negotiations will be successful. The net after-tax amounts received by the Utility under settlements will result in a reduction to the Utility's Settlement Regulatory Asset. In its ERB application filed with the CPUC, the Utility has proposed a methodology whereby ratepayers will receive the benefits of any settlements that occur after the Settlement Regulatory Asset has been refinanced by the issuance of the ERBs.

El Paso Settlement

In June 2003, the Utility, along with SCE the state of California and a number of other parties, entered into a settlement agreement with El Paso Natural Gas Company, or El Paso, 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 California energy crisis. In October 2003, the CPUC approved an allocation of these settlement proceeds. The Utility's natural gas customers would receive approximately $80 million and its electricity customers would receive approximately $215 million of the settlement proceeds over the next 15 to 20 years. In December 2003, the Utility recorded a receivable and corresponding regulatory liability of approximately $200 million for the discounted present value of the future payments. The El Paso settlement became effective in June 2004, at which tim e El Paso made upfront payments totaling approximately $568 million to all parties to the settlement agreement. The Utility's share of El Paso's $568 million upfront payment was approximately $25 million for its natural gas customers and approximately $70 million for its electricity customers. The remaining payments will be made in equal semi-annual installments over the next 15 to 20 years.

The Utility refunded the natural gas payment received from El Paso to core procurement customers in the third quarter of 2004. The portion of the El Paso payment related to core aggregation customers will be refunded beginning January 2005. In accordance with the terms of the Utility's Chapter 11 Settlement Agreement with the CPUC, the Utility recorded the net after-tax amount of the electricity payments received, or approximately $42 million, as an offset to the outstanding balance of the Settlement Regulatory Asset in June 2004.

Enron Settlement

On December 23, 2003, the Utility entered into a settlement agreement with five subsidiaries of Enron Corp., or Enron, settling certain claims between the Utility and Enron, or the Enron Settlement. The Enron Settlement became effective April 20, 2004. On April 23, 2004, the Utility paid Enron cash of $309 million, plus interest of approximately $41 million. These payments have been reflected in the sources and uses of funds table in Note 2 of the Notes to the Consolidated Financial Statements. As a result of the Enron Settlement, the Utility recorded an after-tax credit of approximately $129 million that reduced the Settlement Regulatory Asset during the quarter ended June 30, 2004.

Williams Settlement

On February 24, 2004, the Utility and SCE entered into a settlement agreement with The Williams Companies, or the Williams settlement, settling certain pre-petition claims in the Utility's Chapter 11 proceeding. The settlement was approved by the FERC on July 2, 2004 and by the Bankruptcy Court on August 26, 2004. On August 31, 2004, FERC announced that it will rehear its July 2, 2004 order that approved the settlement. Under the Williams settlement, the Utility expects to receive an after-tax credit of approximately $40 million that will reduce the Settlement Regulatory Asset. The exact amount of the after-tax credit will depend upon the final determination made by the FERC in the pending refund proceeding discussed under "FERC Proceedings" above.

Dynegy Settlement

In April 2004, the Utility, along with SCE, San Diego Gas & Electric Company, the People of the State of California, and a number of other parties, entered into a settlement agreement with Dynegy Inc., or Dynegy, which resolves alleged overcharge and market manipulation claims from the sale of electricity by Dynegy into the California market during the California energy crisis. A definitive agreement to implement the settlement was filed with the FERC on June 28, 2004 and FERC approved the settlement on October 26, 2004. In terms of the settlement, the Utility estimates it could receive an after-tax credit of approximately $50 million that will reduce the Settlement Regulatory Asset. The exact amount of the after-tax credit will depend upon the final determination made by the FERC in the pending refund proceeding discussed under "FERC Proceedings" above.

Duke Settlement

In July 2004, the Utility, along with SCE, San Diego Gas & Electric Company, the People of the State of California through the Attorney General, and other parties, entered into a settlement agreement with Duke Energy Corporation, or Duke, which resolves alleged overcharge and market manipulation claims from the sale of electricity by Duke into the California market during the California energy crisis. In order for this settlement to become effective, it must first be approved by the FERC. The Utility filed a definitive agreement to implement the settlement with the FERC on October 1, 2004. If the Duke settlement is approved, the Utility estimates it will receive an after-tax credit of approximately $50 million that will reduce the Settlement Regulatory Asset and other regulatory balancing accounts. The exact amount of the after-tax credit will depend upon the final determination made by the FERC in the pending refund proceeding discussed under "FERC Proceedings" above.

DWR Contracts

The California Department of Water Resources, or the DWR, provided approximately 24% of the electricity delivered to the Utility's customers for the nine-month period ended September 30, 2004. The DWR purchased the electricity under contracts with various generators. The Utility is responsible for administration and dispatch of the DWR's electricity procurement contracts allocated to the Utility for purposes of meeting a portion of the 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 remains legally and financially responsible for the electricity procurement contracts.

The contracts terminate at various times through 2012, and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered. In the Utility's proposed long-term integrated energy resource plan filed with the CPUC in July 2004, the Utility has not assumed that the electricity provided under DWR contracts will be renewed beyond their current expiration dates.

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 the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility 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, the Utility's issuer rating by Moody's will be no less than A2 and the Utility's long-term issuer credit rating by S&P will be no less than A;
·	The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and
·	The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

The Utility acts as a billing and collection agent for the DWR's sales of its electricity to retail customers and, as a result, amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues. Because of this pass-through nature of amounts collected on behalf of the DWR, and because the Utility is on cost of service ratemaking, changes in the DWR's revenue requirements are not expected to have a material impact on the Utility's results of operations.

PG&E Corporation

On August 27, 2004, PG&E Corporation and NEGT, various NEGT subsidiaries, and the official committee of unsecured creditors, or the OCC, in NEGT's Chapter 11 proceeding pending before the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division, or the Bankruptcy Court, reached a settlement resolving certain tax-related litigation, pending in the U.S. District Court for the District of Maryland, or the District Court. In the litigation, NEGT and its creditors asserted that they were entitled to be paid approximately $414 million of the $533 million that PG&E Corporation received from the IRS for an overpayment of 2002 estimated federal income taxes (approximately $361.5 million achieved by the incorporation of losses and deductions related to NEGT or its subsidiaries and approximately $53 million achieved by the incorporation of certain tax credits related to one of NEGT's subsidiaries). In addition to at least $414 million in damages, the plaintiffs sought punitive damages against PG&E Corporation and two former NEGT directors for breach of fiduciary duty and sought punitive damages against PG&E Corporation for deceit as well as interest, costs of suit, and reasonable attorney fees.

Pursuant to the settlement agreement, on August 30, 2004, PG&E Corporation deposited $30 million in escrow to be paid to NEGT when the settlement became final and non-appealable. At September 30, 2004, the $30 million escrow payment was treated by PG&E Corporation as restricted cash and included as part of the $361.5 million previously reported by PG&E Corporation as restricted cash, while the dispute was pending.

On September 23, 2004, the Bankruptcy Court entered an order approving the settlement agreement and authorized NEGT and its debtor affiliates to execute and deliver the releases and other agreements required to implement the settlement. This order became final and non-appealable on October 4, 2004. On October 12, 2004, the parties (including the creditor committee appointed to represent the interests of NEGT's senior noteholders, which is not a party to the settlement agreement) filed a stipulation dismissing the litigation with the District Court, which the District Court then entered as an order. On October 14, 2004, the settlement agreement became effective. On this date, the $30 million deposited into escrow was paid to NEGT and PG&E Corporation waived certain intercompany claims against NEGT and its debtor subsidiaries. In addition, with certain limited excepti ons, the parties have executed various mutual general releases of substantially all claims between them. In addition, PG&E Corporation and NEGT have entered into a separate agreement under which they have agreed to take certain actions and cooperate with each other with respect to certain tax matters, including future tax returns and audits. As of the settlement's effective date, October 14, 2004, PG&E Corporation no longer treats the remaining amount of $331.5 million as restricted cash.

Environmental Matters

The Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under the Comprehensive Environmental Response Compensation and Liability Act of 1980, or CERCLA, as amended, and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if the Utility did not deposit those substances on the site.

The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of reasonably likely clean-up costs. The Utility reviews its remediation liability on a quarterly basis for each site where it may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at similar sites, and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range. It is reasonably possible that a change in these estimates may occ ur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.

The Utility had an undiscounted environmental remediation liability of approximately $342 million at September 30, 2004, and approximately $314 million at December 31, 2003. During the nine months ended September 30, 2004, the liability increased by approximately $28 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $342 million accrued at September 30, 2004, includes approximately $103 million related to the pre-closing remediation liability associated with divested generation facilities and approximately $239 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the f ormer manufactured gas plant sites. Of the approximately $342 million environmental remediation liability, approximately $145 million has been included in prior rate setting proceedings and the Utility expects that approximately $152 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to ratepayers.

The Utility's undiscounted future costs could increase to as much as $464 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated. The amount of approximately $464 million does not include an estimate for the cost of remediation at known sites owned or operated in the past by the Utility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.

The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility's Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most of these sites, remediation is ongoing in the ordinary course of business or the Utility is in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the clean-up. Other sites identified in the California Attorney General's claims may not, in fact, require remediation or clean-up actions. Environmental claims in the ordinary course of business were not discharged in the Utility's Chapter 11 proceeding and have passed through the Chapter 11 proceeding unimpaired.

Legal Matters

In the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. The most significant of these are discussed below. On the effective date of the Plan of Reorganization, the automatic stay of pending litigation was lifted, so that any state court lawsuits pending before the Utility's Chapter 11 filing that had not yet received relief from the stay can proceed.

Chromium Litigation

There are 14 civil suits pending against the Utility in several California state courts in which plaintiffs allege that exposure to chromium at or near the Utility's compressor stations at Hinkley and Kettleman, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful deaths, or other injury and seek related damages. One of these suits also names PG&E Corporation as a defendant. Currently, there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals filed proofs of claims in the Utility's Chapter 11 case, most of whom also are plaintiffs in the chromium litigation cases. Approximately 1,035 of these claimants filed claims requesting an approximate aggregate amount of $580 million and approximately another 225 claimants filed claims for an "unknown amount." Pursuant to the Plan of Reorganization, these claims have passed thro ugh the Utility's Chapter 11 proceeding unimpaired.

The Utility is responding to the suits in which it has been served and is asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations, exclusivity of workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.

To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from three of the cases for a test trial. Plaintiffs' counsel selected ten of these initial trial plaintiffs, defense counsel selected seven of the initial trial plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 14 motions challenging the test trial plaintiffs' lack of admissible scientific evidence that chromium caused the alleged injuries. The court began hearing argument on two of the motions in February 2004, but no rulings have been issued. Although the trial date previously had been scheduled to begin in March 2004, the court vacated the trial date and no new trial date has been set.

The Utility has recorded a $160 million reserve in its financial statements with respect to the chromium litigation. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at September 30, 2004, the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations.

Recorded Liability for Legal Matters

In accordance with SFAS No. 5, PG&E Corporation and the Utility make a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular case.

The provision for legal matters is included in PG&E Corporation's and the Utility's other noncurrent liabilities in the Consolidated Balance Sheets, and totaled $198 million (which includes the $160 million reserve discussed above) at September 30, 2004, and $205 million at December 31, 2003. PG&E Corporation and the Utility believe that, after taking into account the liability recorded at September 30, 2004, the outcome of these matters will not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or future results of operations.

ITEM 2: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, electricity transmission, and natural gas transportation and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. The Utility served approximately 4.9 million electricity distribution customers and approximately 4.1 million natural gas distribution customers at September 30, 2004. The Utility had approximately $34.1 billion in assets at September 30, 2004 and generated revenues of approximately $8.1 billion in the nine months ended September 30, 2004. The Utility's revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

On April 12, 2004, the Utility's plan of reorganization under Chapter 11 of the U.S Bankruptcy Code, or Plan of Reorganization, became effective. Upon the effective date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon resolution, reinstated certain obligations, and paid other obligations. In March 2004, in anticipation of its emergence from Chapter 11, the Utility issued $6.7 billion in First Mortgage Bonds, or First Mortgage Bonds, and, together with its consolidated subsidiaries, obtained $2.9 billion in credit facilities, in order to finance the Plan of Reorganization.

Appeals of the bankruptcy court's December 22, 2003 order confirming the Plan of Reorganization remain pending. Petitions seeking review of (1) the CPUC's December 18, 2003 order approving the December 19, 2003 settlement agreement reached among PG&E Corporation, the Utility and the CPUC to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement and (2) the CPUC's March 19, 2004 order denying rehearing of its earlier order, also remain pending. PG&E Corporation and the Utility believe these appeals and petitions are without merit. Under applicable federal precedent, once the Plan of Reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this federal precedent, the bankruptcy court's confirmation order or the Settlement Agreement is subsequently overturned or modified, PG&E Corporation and the Utility's fi nancial condition and results of operations could be materially adversely affected. See Note 2 of the Notes to the Condensed Consolidated Financial Statements for more information about the Utility's Chapter 11 proceedings.

PG&E Corporation also owned National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engages in electricity generation and natural gas transportation in the United States, or the U.S. As described below, PG&E Corporation considers its investment in NEGT to be an abandoned asset and accounted for NEGT as discontinued operations in accordance with Statement of Financial Accounting Standards, or SFAS, "Accounting for Impairment or Disposal of Long-Lived Assets," or SFAS No. 144. Under the provisions of SFAS No. 144, the operating results of NEGT and its subsidiaries through July 7, 2003 and for all prior periods are reported as discontinued operations in the Consolidated Statements of Operations. Effective July 8, 2003 , PG&E Corporation accounted for NEGT using the cost method and NEGT is no longer consolidated by PG&E Corporation for financial reporting purposes.

On October 29, 2004 NEGT's plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, became effective. In accordance with the plan of reorganization, PG&E Corporation's equity ownership in NEGT was cancelled. The accounting impacts of this and the effect of a settlement agreement resolving certain tax litigation between PG&E Corporation and NEGT, among others, is discussed below.

PG&E Corporation's and the Utility's results of operations and financial condition since implementation of the Utility's Plan of Reorganization have been, and will continue to be, affected by the following factors, among others:

·	The financial impacts of the Settlement Agreement and the financial impacts of the refinancing of the $2.2 billion, after-tax, regulatory asset provided under the Settlement Agreement;
·	The return to cost of service ratemaking; and
·	The financial and ratemaking impacts of various regulatory decisions, including those that implement settlements reached with various constituencies.

In addition to these factors, future results of operations and financial condition will be affected by the terms under which the Utility and the other California investor-owned utilities will be required to invest in long-term electricity resources, transmission and distribution facilities, and the extent to which the Utility will be provided an opportunity to earn a return on such investments.

As discussed below, PG&E Corporation's fourth quarter 2004 results also will be affected by the cancellation of PG&E Corporation's equity interest in NEGT in connection with NEGT's Chapter 11 plan of reorganization.

As discussed below in "Liquidity and Financial Resource Matters," PG&E Corporation has adopted an initial annual cash dividend target of $1.20 per share ($0.30 quarterly) for 2005, subject to actual declaration by the Board of Directors. PG&E Corporation anticipates distributing up to $1.75 billion to shareholders by the end of 2005 through dividends and stock repurchases.

Other factors are discussed below under "Forward Looking Statements and Risk Factors."

Regulatory Assets Provided Under Settlement Agreement

The Settlement Agreement authorized the Utility to establish a $2.2 billion, after-tax, regulatory asset ($3.7 billion, pre-tax), or the Settlement Regulatory Asset, to be amortized on a "mortgage-style" basis over nine years beginning January 1, 2004. The Settlement Agreement also permitted the Utility to establish a $0.7 billion, after-tax, regulatory asset ($1.2 billion, pre-tax), for the Utility's retained generation assets. In the first quarter of 2004, the Utility recorded approximately $4.9 billion for these regulatory assets and a related after-tax gain on recognition of these regulatory assets of approximately $2.9 billion.

The after-tax amount of the Settlement Regulatory Asset is subject to reduction for any refunds, claim offsets or other credits the Utility receives from energy suppliers relating to specified electricity procurement costs incurred during the California energy crisis. As of September 30, 2004, the Utility has recorded after-tax offsets to the Settlement Regulatory Asset totaling approximately $180 million from supplier settlements.

The Settlement Agreement provides that the unamortized balance of the Settlement 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 the Utility's capital structure reaches 52%, the authorized equity component of the Settlement Regulatory Asset will be no less than 52% for the remaining term. The Utility's retained generation regulatory assets will earn an authorized rate of return on its equity component of 11.22% in 2004 (See note 2 of the Notes to the Consolidated Financial Statements for further information).

Refinancing Supported by a Dedicated Rate Component

Under the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized balance of the Settlement Regulatory Asset and related federal, state and franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of the Plan of Reorganization using a securitized financing supported by a dedicated rate component provided that certain conditions are met. In June 2004, the California Governor signed into law Senate Bill 772, which authorizes the issuance of Energy Recovery Bonds, or ERBs, to be secured by the establishment of a dedicated rate component to refinance the Settlement Regulatory Asset and related taxes. In addition to the authorizing legislation, the following other conditions must be met before a refinancing can occur:

·	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 Settlement Regulatory Asset;
·	The refinancing will not adversely affect the Utility's issuer or debt credit ratings; and
·	The Utility obtains, or decides it does not need, a private letter ruling from the Internal Revenue Service, or the IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

On June 8, 2004, the Utility filed a request for a private letter ruling with the IRS. It is expected that it will take up to six months for the IRS to conclude how it will respond to the request. Also, on July 22, 2004, the Utility filed an application with the CPUC requesting authority to securitize the Settlement Regulatory Asset by issuing ERBs as discussed above, in an aggregate principal amount of up to $3.0 billion in two separate tranches up to one year apart. On October 19, 2004, the CPUC issued a proposed decision authorizing the issuance of the ERBs, subject to the approval of transaction terms by a financing team comprised of CPUC staff and their outside advisors. The CPUC used a similar financing team approach to approve the terms of the Utility's bankruptcy exit financing. Comments on the draft decision are due on November 8, and the Utility expects that the CPUC will issue a final decision by Nove mber 19, 2004. Assuming the timely satisfaction of these remaining conditions, the issuance of the first series of ERBs, in the amount of the after-tax balance of the Settlement Regulatory Asset (estimated to be approximately $1.8 billion), is targeted to occur in January 2005.

After the first series of ERBs are issued, the after-tax balance of the Settlement Regulatory Asset would no longer be a component of rate base and the Utility's revenue and earnings would be reduced accordingly. The Utility would no longer earn the 11.22% return on equity on the Settlement Regulatory Asset. The Utility would recover the principal and interest related to the ERBs from ratepayers through the dedicated rate component. As a result of the expected lower financing costs, the first series of ERBs are expected to create cumulative nominal savings for ratepayers of approximately $700 million.

After the Utility reaches its target capital structure of 52%, it is anticipated that it would use surplus cash including proceeds of the securitization to pay dividends to, or repurchase common stock from, PG&E Corporation, which PG&E Corporation would use in turn to pay dividends to, or repurchase stock from, its shareholders. If the securitization occurs in January 2005, it is expected that the Utility would almost immediately achieve its 52% equity ratio target, thereby enabling PG&E Corporation to pay dividends and repurchase stock in the first half of 2005, as discussed below under "Liquidity and Financial Resources."

The second series of ERBs would be issued to refinance the recovery through rates of the tax payments associated with the principal payments on the first series of ERBs. After the second series is issued, the Utility's revenue and earnings would be reduced through a reduction in revenue requirements creating cumulative nominal savings for ratepayers of approximately $300 million. These savings compensate ratepayers for the time value of money between the time of the Utility's receipt of bond proceeds and when taxes are actually paid, net of interest charges. This credit would decline each year as taxes are paid.

Transition from Frozen Rates to Cost of Service Ratemaking

Beginning January 1, 1998, electricity rates were frozen as required by the California electric industry restructuring law. In response to the California energy crisis, the CPUC increased frozen rates through the imposition of surcharges. Although changes in the Utility's authorized revenue requirements did not impact the revenues received by the Utility under this frozen rate structure, the revenue requirements of the California Department of Water Resources, or DWR, to meet its obligations under its long-term electricity procurement contracts did reduce the Utility's revenues. In January 2004, the CPUC determined that the rate freeze ended on January 18, 2001 and in February 2004 the CPUC approved a rate design settlement to implement an annual electricity rate reduction of approximately $799 million to begin on January 1, 2004.

As a result of the Settlement Agreement and these CPUC decisions, the Utility's rates are now determined based on its costs of service. Electric rates reflect the sum of individual revenue requirement components, including base revenue requirements set by the 2003 General Rate Case, or GRC, described below, revenue requirements for the regulatory assets (including an 11.22% return), provided under the Settlement Agreement, electricity procurement costs, and the DWR's requirement, among others. Changes in any individual revenue requirement will change customers' electricity rates and the Utility's revenues.

On October 15, 2004, the Utility filed its first annual electric true-up advice letter with the CPUC to provide the CPUC information about expected electric rate changes to occur on January 1, 2005. On or before December 31, 2004, the Utility expects to file a supplemental advice letter to reflect November 30, 2004 account balances and any rate changes resulting from proceedings and advice letters that have then been resolved. It is expected that these rate changes would result in an increase in 2005 electric revenues of approximately $315 million.

Approval of 2003 General Rate Case

On May 27, 2004, the CPUC issued a decision in the Utility's 2003 GRC to determine the amount the Utility can collect from customers, or base revenue requirements, to recover its basic business and operational costs for electricity and natural gas distribution operations and for electricity generation operations for 2003 and certain succeeding years. The decision approves the July 2003 and September 2003 settlement agreements reached among the Utility and various consumer groups, including the minimum and maximum yearly increases in revenue requirements, known as attrition adjustments, as discussed below under "Regulatory Matters."

As a result of the GRC decision, during the second quarter the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of unfunded taxes, depreciation, and decommissioning. The net impact of the items recorded in the second quarter, on a pre-tax basis, was approximately $432 million. During the third quarter of 2004, the Utility recorded electricity and natural gas distribution and electricity generation revenues under the new revenue requirements as approved by the 2003 GRC.

Electricity Procurement Costs and Long-Term Electricity Resource Plan

On July 9, 2004, the Utility submitted its long-term integrated energy resource plan, or LTP, for the 2005 through 2014 period to the CPUC in compliance with CPUC decisions and orders regarding electric resource planning. The LTP sets forth the policy framework, strategies and implementation steps for meeting customer electricity demand, or load for the next 10 years to ensure that adequate, reliable, and reasonably priced electrical power and natural gas are provided in a cost-effective and environmentally sound manner. The Utility's target over the 10-year planning horizon is to own 50% of the new generation resources to be developed, with the remaining 50% of such resources to be purchased under long-term contracts. Since there is great uncertainty regarding the extent to which the Utility's residential and small commercial customers, or core customers, and its large commercial and industrial customers, or non-core customers, may be authorized in the future to procure electricity from non-utility load serving entities (such as local publicly owned electric utilities, community choice aggregators or energy service providers, collectively referred to as LSE's), the Utility has requested that the CPUC take certain steps to minimize the risk that the Utility will be unable to recover the investment in long-term resource commitments that it expects it will be required to make. The Utility has requested that the CPUC approve its LTP by December 2004 and authorize the Utility to enter into long-term resource commitments in the second quarter of 2005. The LTP is discussed further under "Electricity Resources" in the Regulatory Matters discussion below.

Forward-Looking Statements and Risk Factors

This combined Quarterly Report on Form 10-Q, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, or the MD&A, contains forward-looking statements, including statements about targeted levels of dividends and stock repurchases, that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," "could," "should," "would," "may," and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements.

Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:

Whether the Implementation of the Utility's Plan of Reorganization Is Disrupted

·	The timing and resolution of the petitions for review that were filed in the California Court of Appeal seeking review of the CPUC's December 18, 2003 decision approving the Settlement Agreement and the CPUC's March 16, 2004 denial of applications for rehearing of the December 18, 2003 decision; and
·	The timing and resolution of the pending appeals of the bankruptcy court's order confirming the Plan of Reorganization.

Operating Environment

·	Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility's ability to earn its authorized rate of return;
·	The level and volatility of wholesale electricity and natural gas prices and supplies, the Utility's ability to manage and respond to the levels and volatility successfully, and the extent to which the Utility is able to timely recover increased costs related to such volatility;
·	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 the Utility's assets or operations or those of third parties on which the Utility relies;
·	Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates, and the extent to which the Utility is able to timely recover its costs in the face of such events;
·	The operation of the Utility's Diablo Canyon nuclear power plant, or Diablo Canyon, which exposes the Utility to potentially significant environmental costs and capital expenditure outlays and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close Diablo Canyon and purchase electricity from more expensive sources;
·	Actions of credit rating agencies;
·	Significant changes in the Utility's relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and
·	Acts of terrorism.

Legislative and Regulatory Environment and Pending Litigation

·	The impact of current and future ratemaking actions of the CPUC, including the risk of material differences between forecasted costs used to determine rates and actual costs incurred;
·	Whether the conditions to securitizing the $2.2 billion after-tax regulatory asset established under the Settlement Agreement are met and, if so, the timing and amount of the securitization;
·	The extent to which the Utility is able to recover its costs incurred in meeting its obligation to supply electricity to customers, whether costs are incurred to meet or manage the Utility's residual net open position (i.e., that portion of the Utility's electricity customers' demand not satisfied by electricity that the Utility generates or has under contract, or by electricity provided under the DWR electricity contracts allocated to the Utility's customers) or to ensure adequate resources as required by the CPUC;
·	Whether the CPUC approves the Utility's long-term electricity resource plan and adopts the Utility's related ratemaking proposals, whether the assumptions and forecasts underlying the long-term resource plan prove to be accurate, and the terms and conditions of the long-term resource commitments the Utility enters into in connection with its long-term resource plan;
·	Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, U.S. Congress, the CPUC, 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;
·	The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons resulting in write-offs of regulatory balancing accounts;
·	How the CPUC administers the capital structure, stand-alone dividend and first priority conditions of the CPUC's decisions permitting the establishment of holding companies for California investor-owned electric utilities;
·	The terms under which the CPUC authorizes the Utility to issue debt and equity in the future, and in particular the extent to which the conditions adopted by the CPUC, such as those contained in the CPUC's general financing authorization decision issued on October 28, 2004 (under which the Utility is authorized to issue debt and preferred stock in the future within certain amounts and for specific purposes) limit the Utility's ability to issue debt in the future;
·	Whether the Utility is 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;
·	Whether the Utility is 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; and
·	The outcome of pending litigation.

Competition

Increased competition as a result of the takeover by condemnation of the Utility's distribution assets, duplication of the Utility's distribution assets or services by local public utilities, 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; and

The extent to which the Utility's distribution customers switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers, the extent to which cities, counties and others in the Utility's service territory begin directly serving the Utility's customers, and the extent to which the Utility's customers become self-generators, results in stranded generating asset costs and non-recoverable procurement costs.

NEGT

Effective July 8, 2003 (the date NEGT filed a voluntary petition for relief under Chapter 11), NEGT and its subsidiaries are no longer consolidated by PG&E Corporation in its Consolidated Financial Statements. Under accounting principles generally accepted in the United States of America, or GAAP, consolidation is generally required for entities owning more than 50% of the outstanding voting stock of an investee, except when control is not held by the majority owner. Legal reorganization and bankruptcy represent conditions that can preclude consolidation in instances where control rests with an entity other than the majority owner. In anticipation of NEGT's Chapter 11 filing, PG&E Corporation's representatives who previously served on the NEGT Board of Directors resigned on July 7, 2003, and were replaced with Board members who are not affiliated with PG&E Corporation. As a result, PG&E Corpor ation no longer retained significant influence over the ongoing operations of NEGT.

Accordingly, PG&E Corporation's negative investment in NEGT of approximately $1.2 billion is reflected as a single amount, under the cost method, within the September 30, 2004 Consolidated Balance Sheets of PG&E Corporation. This negative investment represents the losses of NEGT recognized by PG&E Corporation in excess of its investment in and advances to NEGT. Furthermore, at September 30, 2004 the Consolidated Balance Sheet includes a net deferred tax asset of approximately $432 million, a current tax liability of approximately $145 million, other net liabilities of approximately $28 million and a charge of approximately $77 million, net of tax, in accumulated other comprehensive income, related to NEGT.

On October 29, 2004, NEGT's plan of reorganization became effective, at which time NEGT emerged from Chapter 11 and PG&E Corporation's equity ownership in NEGT was cancelled. On the effective date, PG&E Corporation reversed its negative investment in NEGT and also reversed NEGT-related deferred income tax assets and accumulated other comprehensive income. The resulting net gain has been offset by the $30 million payment made by PG&E Corporation to NEGT pursuant to the parties' settlement of certain tax-related litigation (See Note 6 of the Notes to the Consolidated Financial Statements). A summary of the approximate effect on earnings from discontinued operations is as follows:

(in millions)
Investment in NEGT	$	1,211
Accumulated other comprehensive income	(120)
Cash paid pursuant to settlement of tax related litigation	(30)
Tax Effect	(381)

Gain on disposal of NEGT, net of tax	$	680

Subsequent to the cancellation of its equity interest, at October 29, 2004, PG&E Corporation's Consolidated Balance Sheet includes $166 million in income tax and other net liabilities related to NEGT. Beginning on the effective date of NEGT's plan of reorganization, PG&E Corporation no longer will include NEGT or its subsidiaries in its consolidated income tax returns.

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Consolidated Statements of Operations for the three and nine-month periods ended September 30, 2004, and 2003.

		Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)		2004			2003		2004			2003

Utility
Electric operating revenues		$	2,042	$	2,509	$	5,902	$		5,921
Natural gas operating revenues			581		553		2,198		2,040
Cost of electricity			792		661		2,003		1,823
Cost of natural gas			239		234		1,096		1,040
Operating and maintenance			671		657		2,271		2,098
Recognition of regulatory assets			-		-		(4,900)		-
Depreciation, amortization and decommissioning			405		311		1,054		916
Reorganization professional fees and expenses			-		16		6		116

Operating income			516		1,183		6,570		1,968
Interest income			11		11		44		42
Interest expense			(141)		(237)		(512)		(681)
Other income, net ⁽¹⁾			10		9		26		23

Income before income taxes			396		966		6,128		1,352
Income tax provision			152		383		2,410		508

Income before cumulative effect of a change in accounting principle			244		583		3,718		844
Cumulative effect of a change in accounting principle			-		-		-		(1)

Income available for common stock		$	244	$	583	$	3,718		$	843



PG&E Corporation, Eliminations and Other ⁽²⁾⁽³⁾
Operating revenues		$	-	$	-	$	-		$	(3)
Operating expenses			7		22		28		(30)

Operating income			(7)		(22)		(28)		27
Interest income			4		4		10		7
Interest expense			(18)		(105)		(53)		(176)
Other income (expense), net ⁽¹⁾			(6)		(2)		(72)		(2)

Loss before income taxes			(27)		(125)		(143)		(144)
Income tax provision (benefit)			(11)		(50)		(58)		(54)

Loss from continuing operations			(16)		(75)		(85)		(90)
Discontinued operations			-		2		-			(365)
Cumulative effect of changes in accounting principles			-		-		-			(5)

Net loss		$	(16)	$	(73)	$	(85)		$	(460)



Consolidated Total ⁽³⁾
Operating revenues		$	2,623	$	3,062	$	8,100		$	7,958
Operating expenses (gain)			2,114		1,901		1,558		5,963

Operating income			509		1,161		6,542		1,995
Interest income			15		15		54		49
Interest expense			(159)		(342)		(565)		(857)
Other income (expenses), net ⁽¹⁾			4		7		(46)		21

Income before income taxes			369		841		5,985		1,208
Income tax provision			141		333		2,352		454

Income from continuing operations			228		508		3,633		754
Discontinued operations			-		2		-			(365)
Cumulative effect of changes in accounting principles			-		-		-			(6)

Net income (loss)		$	228	$	510	$	3,633		$	383






⁽¹⁾	Includes preferred dividend requirement as other expense.
⁽²⁾	PG&E Corporation eliminates all intersegment transactions in consolidation.
⁽³⁾	Operating results of NEGT have been reclassified as discontinued operations. See Note 4 of the Notes to the Consolidated Financial Statements.

Utility

As discussed above under "Overview," as of January 1, 2004, the Utility no longer collects frozen electricity rates. Instead the Utility's electric rates are designed to fully recover the Utility's costs of service, including electricity procurement costs.

California legislation has been enacted which allows the Utility to recover all its prospective wholesale electricity procurement costs and requires the CPUC to adjust rates on a timely basis to ensure that the Utility recovers its costs. Accordingly, with the implementation of new CPUC-approved electricity balancing accounts in 2004, electricity procurement costs and items such as changes in sales volumes are not expected to have the same impact on the Utility's results of operations that they had during the California energy crisis when rates were frozen. The level of the Utility's electricity procurement costs will continue to have an impact on cash flows. In addition, a significant outage at any of the Utility's operating facilities may have a material impact on the Utility's results of operations.

The following presents the Utility's operating results for the three and nine-month periods ended September 30, 2004 and 2003. Net income for the first quarter of 2004 reflects a one-time non-cash gain of approximately $2.9 billion, after-tax, due to the recognition of regulatory assets provided under the Settlement Agreement.

Electric Operating Revenues

The following table shows a breakdown of the Utility's electric revenue by customer class:

Three Months Ended
September 30,

Nine Months Ended
September 30,

(in millions)

2004

2003

2004

2003

Electric revenues

$

2,909

$

2,771

$

7,218

$

7,134

DWR pass-through revenue

(560)

(291)

(1,479)

(1,642)

Subtotal

2,349

2,480

5,739

5,492

Miscellaneous

(307)

29

163

429

Total electric operating revenues

$

2,042

$

2,509

$

5,902

$

5,921

As a result of the return to cost-of-service ratemaking in 2004, the Utility records its electric distribution revenues under revenue requirements approved by the 2003 GRC. Differences between the authorized revenue requirements and amounts collected by the Utility from customers in rates are tracked in regulatory balancing accounts, which is reflected in Miscellaneous revenues above.

For the three months ended September 30, 2004, the Utility's electric operating revenues decreased approximately $467 million, or 19%, compared to the same period in 2003 mainly due to the following factors:

·	Electric revenues decreased as a result of the collection of surcharge revenues in the third quarter of 2003. Prior to 2004, the Utility's electric rates were frozen as required by the California electric industry restructuring law. In the third quarter of 2003, the Utility collected approximately $834 million of surcharge revenues under the frozen rate structure, including amounts passed through to DWR for power purchased by DWR on behalf of the Utility's customers. Starting in January 2004, the Utility's rates are determined based on its cost of service;
·	This decrease was partially offset by an increase in electric revenues of approximately $100 million due to the approval of the Utility's 2003 GRC in 2004. The 2003 GRC determines the amount the Utility can collect from its customers, or base revenue requirements (see the "Regulatory Matters" section of this MD&A);
·	The Settlement Agreement established a $2.2 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 the Utility's rate base that is being amortized on a "mortgage-style" basis over nine years beginning January 1, 2004 (see further discussion in Note 2 of the Notes to the Consolidated Financial Statements). As a result of the revenue requirement associated with the Settlement Agreement, the Utility's electric operating revenues increased by approximately $120 million for the three months ended September 30, 2004 as compared to the same period in 2003; and
·	The remaining increase in the Utility's electric operating revenues was due to increases in the Utility's authorized revenue requirements for procurement, transmission, and miscellaneous other electric revenues.

For the nine months ended September 30, 2004, the Utility's electric operating revenues decreased approximately $19 million, or less than 1%, compared to the same period in 2003 due to the following factors:

·	Electric revenues decreased as a result of the collection of surcharge revenues in the nine-month period ended September 30, 2004. Prior to 2004, the Utility's electric rates were frozen as required by the California electric industry restructuring law. During the nine-month period ended September 30, 2003, the Utility collected approximately $1.1 billion of surcharge revenues under the frozen rate structure, including amounts passed through to the DWR for power purchased by the DWR on behalf of the Utility's customers. Starting in January 2004, the Utility's rates are determined based on its cost of service;
·	In addition, the Utility's electric revenues increased by approximately $305 million due to the approval of the Utility's 2003 GRC in 2004. The 2003 GRC determines the amount the Utility can collect from its customers, or base revenue requirements (see the "Regulatory Matters" section of this MD&A);
·	As previously discussed, the Settlement Agreement established a $2.2 billion, after-tax, regulatory asset as a new, separate and additional part of the Utility's rate base that is being amortized on a "mortgage-style" basis over nine years beginning January 1, 2004 (see further discussion in Note 2 of the Notes to the Consolidated Financial Statements). As a result of the revenue requirement associated with the Settlement Agreement, the Utility's electric operating revenues increased by approximately $370 million for the nine months ended September 30, 2004 as compared to the same period in 2003; and
·	The remaining increase in the Utility's electric operating revenues was due to increases in the Utility's authorized revenue requirements for procurement, transmission, and miscellaneous other electric revenues.

Cost of Electricity

The Utility's cost of electricity includes electricity purchase costs and the cost of fuel used by its owned generation facilities but excludes costs to operate its generation facilities. The following table shows a breakdown of the Utility's 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 the Utility's customers:

	Three Months Ended September 30,					Nine Months Ended September 30,

(in millions)	2004		2003			2004		2003

Cost of purchased power	$	787	$	692		$	2,027	$	1,944
Proceeds from surplus sales allocated to the Utility	(35)		(63)			(133)		(197)
Fuel used in own generation	40		32			109		76

Total cost of electricity	$	792	$		661	$	2,003	$		1,823



Average cost of purchased power per kilowatt-hour	$	0.085	$		0.069	$	0.079	$		0.077

Total purchased power (gigawatt-hours)	9,310		9,983			25,589		25,220

The Utility's cost of electricity increased approximately $131 million, or 20%, for the three months ended September 30, 2004, and approximately $180 million, or 10%, for the nine months ended September 30, 2004, compared to the same periods in 2003. Increases in the cost of electricity for both periods were due to an increase in the total cost per kilowatt-hour, or kWh, of electricity purchased in 2004.

Natural Gas Operating Revenues

The following table shows a breakdown of the Utility's natural gas operating revenues:

	Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)	2004		2003		2004		2003

Bundled gas revenues	$	524	$	477	$	2,006	$	1,831
Transportation service-only revenues	57		76		192		209

Total natural gas operating revenues	$	581	$	553	$	2,198	$	2,040



Average bundled price of natural gas sold per Mcf	$	13.48	$	11.97	$	9.92	$	8.84

Total bundled gas sales (in millions Mcf)		39		40		202		207

The Utility's natural gas operating revenues increased approximately $28 million, or 5%, for the three months ended September 30, 2004 and approximately $158 million, or 8%, for the nine months ended September 30, 2004, compared to the same periods in 2003. Increases in natural gas operating revenues for both periods were primarily a result of the approval of the Utility's 2003 GRC in May 2004.

The approval of the GRC resulted in an increase in natural gas revenues of approximately $17 million and $104 million (consisting of a 2004 portion of $52 million and a 2003 portion of $52 million) for the three and nine-month periods ended September 30, 2004, respectively, as compared to the same periods in 2003 (see the "Regulatory Matters" section of this MD&A).

Excluding the effect of the GRC decision discussed above, the average bundled price of natural gas sold increased $1.03 per thousand cubic feet, or Mcf, or 9%, for the three months ended September 30, 2004 and $0.58 per Mcf, or 7%, for the nine months ended September 30, 2004, in comparison to the same periods in 2003. The Utility is permitted by the CPUC to pass increases in the average cost of natural gas to its customers through higher rates.

Cost of Natural Gas

The Utility's cost of natural gas includes the purchase cost of natural gas and transportation costs on interstate and intrastate pipelines. The following table shows a breakdown of the Utility's cost of natural gas:

	Three Months Ended September 30,				Nine Months Ended September 30,

(in millions)	2004		2003		2004		2003

Cost of natural gas sold	$	209	$	205	$	999	$	942
Cost of gas transportation	30		29		97		98

Total Cost of Natural Gas	$	239	$	234	$	1,096	$	1,040



Average price of natural gas purchased per Mcf	$	5.36	$	5.13	$	4.95	$	4.55

Total natural gas purchased (in millions Mcf)		39		40		202		207

The increase in the Utility's total cost of natural gas of approximately $5 million, or 2%, and $56 million, or 5%, for the three and nine-month periods ended September 30, 2004, was primarily due to an increase in the average market price of natural gas purchased.

The increase in the average market price of natural gas purchased of $0.23 per Mcf, or 4%, in the three months ended September 30, 2004, resulted in a $9 million increase in the total cost of natural gas. This increase was offset by a decrease in sales volume of 1 million Mcf, or 3%, resulting in a $4 million decrease in the total cost of natural gas.

The increase in the average market price of natural gas purchased of $0.40 per Mcf, or 9%, in the nine months ended September 30, 2004, resulted in a $80 million increase in the total cost of natural gas. This increase was offset by a decrease in sales volume of 5 million Mcf, or 2%, resulting in a $24 million decrease in the total cost of natural gas.

Operating and Maintenance

Operating and maintenance expenses consist mainly of the Utility's costs to operate its electricity and natural gas facilities, maintenance expenses, customer accounts and service expenses, and administrative and general expenses.

During the three months ended September 30, 2004, the Utility's operating and maintenance expenses increased $14 million, or 2%, as compared to the same period in 2003. This increase is primarily a result of increased expenses associated with customer incentive programs (which have associated increases in revenues), the recorded liability for legal matters, and the Utility's core gas firm storage charges. These increases were partially offset by a wage adjustment in the third quarter of 2003, with no similar amount in 2004.

During the nine months ended September 30, 2004, the Utility's operating and maintenance expenses increased $173 million, or 8%, as compared to the same period in 2003. This increase is primarily due to an increase in expenses related to the various provisions of the Settlement Agreement, including obligations to invest in clean energy technology and donation of land, expenses associated with customers incentive programs (which have associated increases in revenues), and the Utility's core gas firm storage charges. This increase is also a result of reductions to the estimated liability for environmental matters for the nine months ended September 30, 2003, with no similar reductions in 2004.

Interest Expense

The Utility's interest expense decreased approximately $96 million, or 41%, for the three months ended September 30, 2004, and approximately $169 million, or 25%, for the nine months ended September 30, 2004, compared to the same periods in 2003 due to a lower average amount of unpaid debt accruing interest and a lower weighted average interest rate on debt outstanding during 2004.

Income Tax Expense

The Utility's tax expense decreased approximately $231 million, or 60%, for the three months ended September 30, 2004 compared to the same period in 2003, mainly due to a decrease in pre-tax income of approximately $570 million in 2004.

The Utility's tax expense increased approximately $1.9 billion, or 374%, as compared to the same period in 2003, mainly due to an increase in pre-tax income of $4.8 billion for the nine months ended September 30, 2004 as a result of the recognition of regulatory assets associated with the Settlement Agreement, as compared to the same period in 2003. This increase was partially offset by the recognition of tax regulatory assets established upon receipt of the Utility's 2003 GRC decision.

PG&E Corporation, Eliminations and Others
Operating Revenues and Expenses

PG&E Corporation's revenues consist mainly of billings to the Utility for services rendered, all of which are eliminated in consolidation. PG&E Corporation's operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation's operating expenses are allocated to affiliates. Operating expenses allocated to affiliates are eliminated in consolidation.

In the three-month period ended September 30, 2004. PG&E Corporation's operating expenses decreased by approximately $15 million for the three-month and increased by approximately $58 million for the nine-month periods ending September 30, 2004, compared to the same periods in 2003. The decrease in operating expenses for the three-month period was primarily due to lower external legal fees and other expenses related to NEGT's Chapter 11 proceeding. The increase in operating expenses for the nine-month period was primarily due to increased external legal fees and other expenses related to the NEGT's and Utility's Chapter 11 proceedings, and other administrative expenses in 2004.

Interest Expense

PG&E Corporation's interest expense is not allocated to its affiliates. In the three-month period ended September 30, 2004, PG&E Corporation's interest expense decreased by approximately $87 million, or 83%, compared to the same period in 2003. For the nine-month period ended September 30, 2004, PG&E Corporation's interest expense decreased by approximately $123 million, or 70%, compared to the same period in 2003. The decreases during these periods compared to the same periods in 2003 were due to a reduction in principal debt amount outstanding, lower interest rate, and a write-off of approximately $89 million of unamortized loan fees, loan discount, and prepayment fees associated with the repayment in July 2003 of approximately $735 million of principal under PG&E Corporation's existing credit agreement in 2003 with no similar charge in 2004.

Other Expense

PG&E Corporation's other expense increased by approximately $4 million and approximately $70 million for the three and nine-month periods ended September 30, 2004, compared to the same periods in 2003. These increases during both periods were primarily due to a pre-tax charge to earnings of approximately $5 million in the third quarter and approximately $70 million year-to-date, related to the change in market value of non-cumulative dividend participation rights included within PG&E Corporation's $280 million of 9.50% Convertible Subordinated Notes.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

At September 30, 2004, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $1.9 billion, and restricted cash of approximately $2.4 billion. PG&E Corporation and the Utility maintain separate bank accounts. At September 30, 2004, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $0.9 billion and restricted cash of approximately $361 million, which included $30 million related to a settlement agreement with NEGT and certain of its creditors resolving tax-related issues. On October 14, 2004, when the settlement agreement became effective, $30 million was released from escrow and paid to NEGT. At September 30, 2004, the Utility had cash and cash equivalents of approximately $980 million, and restricted cash of approximately $2.0 billion, which pertains to amounts deposited in escrow pending resolution of disputed claims mad e in the Chapter 11 case. PG&E Corporation and the Utility primarily invest their cash in money market funds and in short-term obligations of the U.S. Government and its agencies.

Utility

During its Chapter 11 proceeding, the Utility did not have access to the capital markets and met all its ongoing cash requirements, including its capital expenditure requirements, with cash generated by its operations. In addition, the Utility paid interest on certain pre-petition liabilities and repaid the principal of maturing mortgage bonds with bankruptcy court approval.

In March 2004, in anticipation of the Utility's emergence from Chapter 11, the Utility issued $6.7 billion of First Mortgage Bonds and the Utility and its consolidated subsidiaries entered into $2.9 billion of credit facilities. The Utility also obtained an interim $400 million cash collateralized letter of credit facility, which was terminated on April 12, 2004, the effective date of the Utility's Plan of Reorganization, or the Effective Date, and the letters of credit outstanding were transferred to the Utility's $850 million working capital facility. Proceeds from the sale of the First Mortgage Bonds, borrowings of approximately $1.1 billion, and approximately $2.4 billion of cash on hand were used on the Effective Date to pay allowed creditor claims or deposited into escrow to pay disputed claims when resolved. See Note 3 of the Notes to the Consolidated Financial Statements for further discussion of the First Mortgage Bonds and the Utility's new credit facilities.

On June 29, 2004, the Utility entered into four separate loan agreements with the California Pollution Control Financing Authority, which issued $345 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds 2004 Series A, B, C, and D to redeem the Pollution Control Revenue Bonds 1992 Series A and B and the 1993 Series A and B totaling $345 million held by the Utility. The funds received by the Utility were used to repay the $345 million term loan facility.

On October 3, 2004, the Utility partially redeemed Floating Rate Mortgage Bonds due in 2006 in the aggregate principal amount of $500 million. The $500 million principal amount of Floating Rate First Mortgage Bonds due in 2006 was selected from all Floating Rate First Mortgage Bonds due in 2006 in accordance with the procedures of The Depository Trust Company.

The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the nine months ended September 30, 2004 and 2003.

Operating Activities

The Utility's cash flows from operating activities for the nine months ended September 30, 2004 and 2003 were as follows:

	Nine Months Ended September 30,

(in millions)	2004		2003


Net income	$	3,735	$	861
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	1,054		916
Recognition of regulatory assets, net of tax	(2,904)		-
Change in accounts payable	77		350
Change in income taxes payable	87		437
Change in other working capital	285		77
Other uses of cash:
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	(1,022)		(83)
Other changes in operating assets and liabilities	96		(19)

Net cash provided by operating activities	$	1,408	$	2,539

Net cash provided by operating activities decreased by approximately $1.1 billion during the nine months ended September 30, 2004, compared to the same period in 2003. This decrease was mainly due to an increase in payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise of $939 million during the nine months ended September 30, 2004, compared to the same period in 2003. This increase was a result of the payment of all allowed creditor claims on the Effective Date.

Investing Activities

The Utility's investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash flows from operating activities have been sufficient to fund the Utility's capital expenditure requirements for the nine months ended September 30, 2004.

The Utility's cash flows from investing activities for the nine months ended September 30, 2004 and 2003 were as follows:

	Nine Months Ended September 30,

(in millions)	2004		2003


Capital expenditures	$	(1,110)	$	(1,182)
Proceeds from sale of assets	28		14
Increase in restricted cash	(1,751)		-
Other investing activities	(50)		(25)

Net cash used by investing activities	$	(2,883)	$	(1,193)

Net cash used by investing activities increased by approximately $1.7 billion during the nine months ended September 30, 2004, compared to the same period in 2003. This increase was due to an increase in restricted cash of approximately $1.8 billion during the nine months ended September 30, 2004, compared to the same period in 2003, mainly due to funds deposited into escrow to pay disputed claims when resolved. Other investing activities increased mostly due to an increase in nuclear fuel inventory that was partially offset by a decrease in nuclear decommissioning funding.

Financing Activities

Prior to the implementation of the Plan of Reorganization and during its Chapter 11 proceeding, the Utility's financing activities were limited to repayment of secured debt obligations as authorized by the bankruptcy court. During this period, the Utility did not have access to the capital markets. As a result of its emergence from Chapter 11, the Utility has issued significant amounts of debt in connection with the implementation of the Plan of Reorganization and established a working capital facility and an accounts receivable financing facility for the purposes of funding its operating expenses and seasonal fluctuations in working capital and providing letters of credit.

The Utility's cash flows from financing activities for the nine months ended September 30, 2004 and 2003 were as follows:

	Nine Months Ended September 30,

(in millions)	2004		2003


Net proceeds from issuance of long-term debt	$	7,346	$	-
Long-term debt issued, matured, redeemed or repurchased		(7,552)		(280)
Rate reduction bonds matured	(213)		(213)
Preferred dividends paid	(88)		-
Preferred stock with mandatory redemption provisions redeemed	(15)		-
Other financing activities	(2)		(1)

Net cash used by financing activities	$	(524)	$	(494)

For the nine months ended September 30, 2004, net cash used by financing activities increased by approximately $30 million compared to the same period in 2003. This increase was mainly due to the following factors:

·	In March 2004, in connection with the implementation of the Utility's Plan of Reorganization, the Utility consummated a public offering of $6.7 billion in First Mortgage Bonds. On the Effective Date, the Utility entered into pollution control bond bridge loans in the amount of $454 million (see Note 3 of the Notes to the Consolidated Financial Statements). In June 2004, the Utility entered into four separate loan agreements with the California Pollution Control Financing Authority, which issued $345 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds (see Note 3 of the Notes to the Consolidated Financial Statements). Partially offsetting these proceeds are issuance costs of approximately $153 million associated with the $6.7 billion in First Mortgage Bonds;
·	In April 2004, the Utility used the net proceeds of approximately $6.5 billion from the offering, together with available cash on hand to pay creditor claims, including approximately $7.5 billion of long-term debt, and deposit funds in escrow for the payment of disputed claims;
·	Approximately $213 million of rate reduction bonds matured during the nine months ended September 30, 2004;
·	Approximately $88 million of preferred stock dividends were paid during the nine months ended September 30, 2004; and
·	Approximately $15 million of preferred stock with mandatory redemption provisions was redeemed during the nine months ended September 30, 2004.

PG&E Corporation

At September 30, 2004, PG&E Corporation had stand-alone cash and cash equivalents of approximately $0.9 billion and restricted cash of approximately $361 million. PG&E Corporation's sources of funds are dividends from the Utility, issuance of its common stock and external financing. The Utility did not pay any dividends to PG&E Corporation during the first nine months of 2004 or 2003.

On August 27, 2004, PG&E Corporation reached a settlement with NEGT and certain of its creditors resolving certain tax-related issues and waiving certain inter-company claims. Pursuant to the settlement agreement, PG&E Corporation deposited $30 million in escrow to be paid to NEGT when the settlement became final and non-appealable. At September 30, 2004, this $30 million was treated by PG&E Corporation as restricted cash. Subsequently, on October 14, 2004, the $30 million was released from escrow and paid to NEGT and the remaining $331 million that PG&E Corporation had previously treated as restricted cash, while the dispute was pending, is no longer considered restricted.

Operating Activities

PG&E Corporation's consolidated cash flows from operating activities consist mainly of billings to the Utility for services rendered and payments for employee compensation and goods and services provided by others to PG&E Corporation. PG&E Corporation also incurs interest costs associated with its debt. PG&E Corporation's interest costs are not passed on to its affiliates nor are the benefits or detriments of the consolidated tax return. The benefits of the consolidated tax return have created cash flow from operating activities for PG&E Corporation during the nine months ended September 30, 2004 and 2003. NEGT's tax dispute with PG&E Corporation is discussed above.

PG&E Corporation's consolidated cash flows from operating activities for the nine months ended September 30, 2004 and 2003 were as follows:

	Nine Months Ended September 30,

(in millions)	2004		2003


Net income	$	3,633	$	383
Loss from discontinued operations	-		365
Cumulative effect of changes in accounting principles	-		6

Net income from continuing operations	3,633		754
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	1,056		910
Recognition of regulatory asset, net of tax	(2,904)		-
Deferred income taxes and tax credits, net	364		339
Other deferred charges and noncurrent liabilities	(183)		636
Loss from retirement of long-term debt	(18)		89
Other changes in operating assets and liabilities	(458)		188

Net cash provided by operating activities	$	1,490	$	2,916

Net cash provided by operating activities decreased by $1.4 billion during the nine months ended September 30, 2004, compared to the same period in 2003. This decrease was primarily related to decreases in other deferred charges and noncurrent liabilities and the Utility's decrease in net cash provided from operating activities as discussed above, partially offset by increases in deferred income taxes and tax credits, net.

Investing Activities

PG&E Corporation, on a stand-alone basis, did not have any material investing activities in the nine months ended September 30, 2004 or 2003.

Financing Activities

PG&E Corporation's consolidated cash flows from financing activities consist mainly of cash generated from debt refinancings and the issuance of common stock.

PG&E Corporation's consolidated cash flows from financing activities for the nine months ended September 30, 2004, and 2003 were as follows:

	Nine Months Ended September 30,

(in millions)	2004		2003


Net proceeds from issuance of long-term debt	$	7,346	$	582
Long-term debt matured, redeemed or repurchased	(7,553)		(1,067)
Rate reduction bonds matured	(213)		(213)
Preferred stock with mandatory redemption provisions redeemed	(15)		-
Preferred dividends paid	(88)		-
Common stock issued	121		120
Other, net	(2)		(2)

Net cash used by financing activities	$	(404)	$	(580)

PG&E Corporation's consolidated net cash used by financing activities decreased by $176 million for the nine months ended September 30, 2004, compared to the same period in 2003. This decrease was primarily related to the Utility's financing activities, as discussed above.

Future Liquidity

As a result of its emergence from Chapter 11 on April 12, 2004, the Utility expects to fund its operating expenses and capital expenditures substantially from internally generated funds although it may issue debt for these purposes in the future. In addition, the Utility expects to use the amount remaining under its $850 million working capital facility for the purposes of funding its operating expenses and seasonal fluctuations in working capital and providing letters of credit. In addition, the Utility has entered into a $650 million accounts receivable financing. At September 30, 2004, the Utility did not have any borrowings under either facility. Under the $850 million facility, $163 million was outstanding to support letters of credit at September 30, 2004.

On October 3, 2004, the Utility redeemed $500 million aggregate principal amount of Floating Rate First Mortgage Bonds and expects that its cash on hand, together with cash from operating activities and available amounts under the facilities described above, will provide for seasonal fluctuations in cash requirements and will be sufficient to fund its operations and its capital expenditures for the foreseeable future.

On October 15, 2004, the trustee under the indenture for PG&E Corporation's 6⅞% Senior Secured Notes due July 15, 2008, or Senior Secured Notes, notified the holders of the Senior Secured Notes that these will be redeemed in full on November 15, 2004. Redemption of the Senior Secured Notes will require approximately $664.5 million of PG&E Corporation's cash, which includes a redemption premium of approximately $50.7 million and $13.8 million of interest that has accrued since the last interest payment date. PG&E Corporation's ability to meet its debt obligations, pay dividends and make stock repurchases are based upon dividends received from, and stock repurchases made by, the Utility as discussed below.

Dividends and Share Repurchases

PG&E Corporation did not declare or pay a dividend during the Utility's Chapter 11 proceeding. Further, until the Senior Secured Notes issued by PG&E Corporation are redeemed or rated Baa3 or better by Moody's Investors Service, or Moody's, and BBB- or better by Standards & Poor's, or S&P, PG&E Corporation is prohibited from declaring or paying dividends or repurchasing its common stock unless certain financial criteria are met. Notwithstanding this restrictive covenant, PG&E Corporation may (1) pay regular quarterly dividends funded from proceeds of cash distributions to PG&E Corporation from the Utility, (2) repurchase common stock with proceeds of sales of PG&E Corporation equity, including stock option exercises, and (3) make certain other limited repurchases of common stock. PG&E Corporation can redeem the Senior Secured Notes at any time at its option at a premium. As dis cussed above, the Senior Secured Notes will be redeemed in full on November 15, 2004.

While in Chapter 11, the Utility was prohibited from paying any common or preferred stock dividends without bankruptcy court approval. The Utility resumed the payment of preferred stock dividends on May 15, 2004. On July 20, 2004, the Utility declared dividends on all the outstanding 11 series of its preferred stock for the three months ending July 31, 2004. The dividends were paid on August 15, 2004, to the shareholders of record on July 30, 2004.

On October 20, 2004, the Board of Directors of PG&E Corporation and the Board of Directors of the Utility each approved a common stock dividend policy and a target dividend payout ratio range (the proportion of earnings paid out as dividends) of 50-70%. Although the Boards of Directors deferred the actual declaration of a common stock dividend at least until after the Utility achieves the target equity ratio discussed below, the Board of Directors of PG&E Corporation adopted an initial annual cash dividend target of $1.20 per share ($0.30 quarterly).

Each dividend policy was designed to meet the following three objectives:

·	Comparability: Pay a dividend competitive with the securities of comparable companies based on payout ratio and, with respect to PG&E Corporation, yield (i.e., dividend divided by share price);
·	Flexibility: Allow sufficient cash to pay a dividend and to fund investments while avoiding the necessity to issue new equity unless PG&E Corporation's or the Utility's capital expenditure requirements are growing rapidly and PG&E Corporation or the Utility can issue equity at reasonable cost and terms; and
·	Sustainability: Avoid reduction or suspension of the dividend despite fluctuations in financial performance except in extreme and unforeseen circumstances.

The target dividend payout ratio range was based on an analysis of dividend payout ratios of comparable companies. The initial dividend target was chosen in recognition of the Utility's current credit rating and the potential capital investments that the Utility may make in the future to provide electricity resource adequacy in compliance with future regulatory requirements and an approved long-term electricity resources plan.

After the Utility reaches its target equity ratio of 52% as provided in the Settlement Agreement, and ERBs in the approximate amount of $1.8 billion are issued in January 2005 to refinance the Settlement Regulatory Asset, it is anticipated that the Utility would use surplus cash to pay dividends to, or repurchase common stock from, PG&E Corporation which PG&E Corporation would use in turn to pay dividends to, or repurchase stock from, its shareholders. Assuming the issuance of ERBs in January 2005 in the approximate amount of $1.8 billion, PG&E Corporation estimates that it would have up to $1.75 billion to distribute to its shareholders through the end of 2005 through dividends and stock repurchases. PG&E Corporation estimates that an additional approximately $950 million will be available through the end of 2006 to distribute to shareholders through dividends and stock repurchases or for capital i nvestments beyond the level of capital expenditures already assumed.

The initial annual cash dividend target of $1.20 per share is based on many assumptions, including that:

·	The Utility remains under cost-of-service regulation by the CPUC and, with respect to electric transmission, the FERC;
·	The CPUC and the FERC authorize sufficient revenues for the Utility to recover its energy procurement and base expenses;
·	The Utility's authorized return on equity for all operations remains at least at 11.22%;
·	The first series of ERBs in the approximate amount of $1.8 billion is issued in early 2005 and the second series is issued in early 2006;
·	Annual Utility capital expenditures average $1.9 billion in 2005 and 2006 (these forecasted capital expenditures do not include amounts for new generation development or implementation of an advanced metering system);
·	Total gas and electric rate base, including retained generation facilities and the Settlement Regulatory Asset, of approximately $15.3 billion for 2005 and $16.0 billion for 2006; and
·	The Utility manages its operating expenses and capital expenditures to earn the full authorized rate of return within revenues authorized under the CPUC's decision in the Utility's 2003 GRC and subsequent adjustments for inflation through 2006.

Each Board of Directors retains authority to change its common stock dividend policy and its dividend payout ratio at any time, especially if unexpected events occur that would change the Board's views as to the prudent level of cash conservation. No dividends are payable until after the respective Board of Directors declares a dividend. In order to declare a dividend, each Board of Directors must determine that the applicable requirements of California law and the CPUC have been satisfied.

CAPITAL EXPENDITURES AND COMMITMENTS
Capital Expenditures

The Utility's distribution, generation and transmission operating assets generally consist of long-lived assets with significant construction and maintenance costs. The Utility's annual capital expenditures are expected to average approximately $1.9 billion annually over the next two years, excluding costs associated with potential new generation development or implementation of advanced metering systems. This is expected to result in an average annual rate base of approximately $15.3 billion in 2005 and approximately $16.0 billion in 2006 (excluding the Settlement Regulatory Asset). It is anticipated that the Utility will be required to make substantial capital expenditures in connection with the implementation of its long-term electricity resource plan as described below.

Contractual Commitments

The Utility's 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. In connection with the implementation of the Plan of Reorganization, the Utility issued $6.7 billion in First Mortgage Bonds, entered into $2.9 billion in credit facilities, and obtained a $400 million cash collateralized letter of credit facility. On the Effective Date, the $400 million letter of credit facility was cancelled and the outstanding letter of credit balance was transferred to the Utility's $850 million revolving credit facility. In addition, the Utility paid approximately $8.4 billion in cash to holders of allowed claims and deposited approximately $1.8 billion into escrow accounts for the paym ent of disputed claims.

Utility
Power Purchase Agreements

Natural Gas Supply and Transportation Commitments

At September 30, 2004, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

(in millions)

2004	$	371
2005	714
2006	26
2007	7
2008	-
Thereafter	-

Total	$	1,118

Nuclear Fuel Agreements

At September 30, 2004, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)

2004	$	128
2005	28
2006	29
2007	38
2008	30
Thereafter	64

Total	$	317

Transmission Control Agreement

The Utility has entered into a Transmission Control Agreement, or TCA, with the California Independent System Operator, or the ISO, and other participating transmission owners (including Southern California Edison, or SCE, San Diego Gas & Electric Company, and several municipal utilities) under which the transmission owners have assigned operational control of their electricity transmission systems to the ISO. The Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA.

WAPA Commitments

Other Commitments

(in millions)

2004	$	97
2005	95
2006	32
2007	17
2008	14
Thereafter	5

Total	$	260

REGULATORY MATTERS

The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction to, among other things, set the rates, terms and conditions of service for the Utility's electricity generation, procurement and distribution, natural gas distribution, and natural gas transportation and storage services in California. 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 Utility's rates are determined based on its costs of service. As discussed above under "Overview," as of January 1, 2004, the Utility's electric rates reflect the sum of individual revenue requirement components. Changes in any individual revenue requirement will change customers' electricity rates and the Utility's revenues. On October 15, 2004, the Utility filed its first annual electric true-up advice letter with the CPUC to provide the CPUC information about expected electric rate changes to occur on January 1, 2005 to reflect amortization of balancing account balances authorized for recovery in 2005, update the Settlement Regulatory Asset revenue requirement for 2005, consolidate rate changes expected to result from resolution of various pending proceedings or approval of various advice filings before December 31, 2004, and provide information on FERC-jurisdictional rate changes to be implemented on Janua ry 1, 2005. On or before December 31, 2004, the Utility expects to file a supplemental advice letter to reflect November 30, 2004 account balances and any rate changes resulting from proceedings and advice letters that have then been resolved. It is expected that these rate changes would result in an increase in 2005 electric revenues of approximately $315 million.

2003 General Rate Case

·	$2.5 billion for electricity distribution operations, representing a $236 million increase over the previously authorized amount;
·	$912 million for electricity generation operations, representing a $38 million increase over the previously authorized amount; and
·	$927 million for natural gas distribution operations, representing a $52 million increase over the previously authorized amount.

	2004	2005	2006

Electricity and Natural Gas Distribution
Minimum	2.00%	2.25%	3.00%
Multiplier	Change in CPI	Change in CPI	Change in CPI+1%
Maximum	3.00%	3.25%	4.00%

Electricity Generation
Minimum	1.50%	1.50%	2.50%
Multiplier	Change in CPI	Change in CPI	Change in CPI+1%
Maximum	3.00%	3.00%	4.00%

As a result of the approval of the 2003 GRC, during the second quarter of 2004, the Utility recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets and unfunded taxes, depreciation, and decommissioning. During the third quarter of 2004, the Utility recorded electricity and natural gas distribution and electricity generation revenues under the new revenue requirements as approved by the 2003 GRC. The impact of the 2003 GRC on the third quarter of 2004 is discussed in the Results of Operations section above. The net impact of the items which were recorded in the second quarter, on a pre-tax basis is as follows:

					Amount Previously Recorded in 2003

	Impact Related to						Net 2004 Adjustment

(in millions)	2003		2004


Electricity revenue	$	273	$	152	$	268	$	157
Natural gas revenue	52		25		-		77
Electricity attrition	-		48		-		48
Natural gas attrition	-		9		-		9
Regulatory assets, net	(17)		158		-		141

Total	$	308	$	392	$	268	$	432

Another phase of the GRC was established to address the Utility's response to the December 2002 storm and the Utility's reliability performance. In October 2004, the CPUC approved certain storm response improvement initiatives as well as a reliability performance incentive mechanism for the years 2005 through 2007. Under the performance incentive mechanism the Utility could receive up to $24 million each year depending on the extent to which the Utility exceeds the reliability performance improvement targets, but could be required to pay a penalty of up to $24 million a year depending on the extent to which it fails to meet the targets. The decision does not provide the Utility with additional revenues to meet the reliability standards, but does include a wide margin of error around the targets in order to mitigate potential penalties. PG&E Corporation and the Utility are unable to predict whether or not the Utility will incur a reward or penalty related to the performance incentive mechanism.

Cost of Capital Proceedings

The CPUC last authorized a cost of capital for the Utility in 2003, setting the return on equity at 11.22% and its cost of debt at 7.57%. The Utility's last authorized capital structure was 48.00% common equity, 46.20% long-term debt and 5.80% preferred equity.

The Settlement Agreement provides that from January 1, 2004 until Moody's has issued an issuer rating for the Utility of not less than A3 or S&P has issued a long-term issuer credit rating for the Utility of not less than A-, the Utility's authorized return on equity will be no less than 11.22% per year and its authorized equity ratio will be no less than 52%. However, for 2004 and 2005, the Utility's authorized equity ratio will equal the greater of the proportion of equity approved in the Utility's 2004 and 2005 cost of capital proceedings, or 48.6%.

On May 12, 2004, the Utility filed a cost of capital application with the CPUC to recover in rates (1) its actual cost of capital (long-term debt and preferred stock) from January 1, 2004 through April 11, 2004, (2) its new cost of capital resulting from its Chapter 11 exit financing that became effective on April 12, 2004, and (3) costs associated with interest rate hedges for its Chapter 11 exit financing. For its electricity and natural gas distribution operations, natural gas transmission and storage, and electricity generation operations, the Utility has requested the CPUC authorize the following cost of capital for 2004 and 2005:

	2004						2005

		Cost		Capital Structure		Weighted Cost		Cost		Capital Structure		Weighted Cost


Long-term debt	5.82%		48.2%		2.81%		5.94%		45.5%		2.70%
Preferred stock	6.76%		2.8%		0.19%		6.42%		2.5%		0.16%
Common equity	11.22%		49.0%		5.50%		11.60%		52.0%		6.03%
Return on rate base					8.49%						8.90%

The Utility's annual revenue requirement for 2004 would decrease by approximately $109 million compared to the currently authorized revenue requirement. As of September 30, 2004, the Utility recorded a $71 million reserve against operating revenues for the difference between its currently authorized rate of return on rate base and the lower rate of return on rate base requested in its cost of capital application.

For 2005, the requested capital structure reflects an assumption that ERBs are sold on January 1, 2005 to refinance the Settlement Regulatory Asset, and that the proceeds of the issuance are used to rebalance the Utility's capital structure in order to attain the target capital structure of 52% equity ratio as provided in the Settlement Agreement and to fund infrastructure capital expenditures. Due to energy supplier refunds which are expected to be offset against the Settlement Regulatory Asset, the projected amount of ERBs targeted for issuance in January 2005 is approximately $1.8 billion. After the issuance of ERBs, the Utility would not collect the 11.22% return on equity on the Settlement Regulatory Asset. Instead, the Utility would recover the principal and interest related to the ERBs from customers through the dedicated rate component.

The Utility has proposed to include any electric revenue requirement change authorized in this proceeding in rates effective January 1, 2005. The Utility also has proposed to include any gas revenue requirement changes authorized in this proceeding in the next gas transportation rate change, annual true-up or the biennial cost allocation proceeding.

The Utility expects the CPUC will issue a final decision on the cost of capital proceeding in December 2004.

DWR Revenue Requirements

In September 2003, 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 for its costs of purchasing electricity on behalf of the Utility's customers. In January 2004, the CPUC adopted an interim allocation of the DWR's proposed 2004 revenue requirements among the three California investor-owned electric utilities' customers. The Utility's customers' share of the DWR power charge revenue requirement is approximately $1.8 billion after consideration of a DWR 2001-2002 adjustment approved in a CPUC decision in January 2004. The January 2004 decision allocated the bond charge revenue requirement among the three California investor-owned electric utilities' customers on an equal cents per kWh basis, which resulted in approximately $369 million being allocated to the Utility's customers.

In April 2004, the DWR submitted a supplemental determination of its 2004 revenue requirement to the CPUC reducing the amount of power charge revenues the DWR will recover from electric customers statewide in 2004 by $245 million. The reduction is primarily driven by higher than projected power charge revenues received by the DWR in 2003, and an increased forecast of revenues from the sale of surplus power in 2004.

In August 2004, the CPUC approved allocation of the 2004 DWR supplemental revenue requirements using the interim allocation methodology adopted in its January 2004 decision, retroactive to January 1, 2004.

In September 2004, the DWR filed a proposed $3.9 billion 2005 power charge revenue requirement and a proposed 2005 bond charge revenue requirement of approximately $886 million with the CPUC. The CPUC is considering several proposed decisions for the permanent allocation of the DWR revenue requirement for 2004 and beyond among the three utilities' customers. A final decision on a permanent allocation methodology is expected in the fourth quarter of 2004. The Utility cannot predict the final outcome of this matter.

As a result of the transition from frozen rates and the electricity procurement recovery mechanism described below, the collection of DWR revenue requirements, or any adjustments thereto, is not expected to materially affect the Utility's results of operations.

Electricity Resources

Effective January 1, 2003, under California law (Assembly Bill 57, or AB 57), the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the authorized revenue requirement and actual costs incurred under the Utility's 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 forecast aggregate over-collections or under-collections exceed 5% of the utility's prior year electricity procurement revenues, excluding amounts collected for the DWR. The Utility's ERRA trigger threshold for 2004 is $191 million. These mandatory adjustments will continue until January 1, 2006. The Utility has requested that the CPUC extend these mandatory adjustments through at least the 10-year period covered by the Utility's proposed long-term electricity procurement plan, or LTP, that was filed with the CPUC in July 2004 (see further discussion below). The CPUC's review of the Utility's procurement activities examines the Utility's least-cost dispatch of its resource portfolio, including the DWR allocated contracts, fuel expenses for the Utility's electricity generation facilities, contract administration (including administration of the DWR allocated contracts), and the Utility's electricity procurement contracts. As a result of this review, some of the Utility's procurement costs could be disallowed up to a maximum of two times the Utility's administration costs associated with procurement. At September 30, 2004, the ERRA had an under-collected balance of approximately $85 million, which is below the 5% trigger for mandatory adjustment of rates. This balance reflec ts the decision issued by the CPUC on June 9, 2004, adopting an interim ERRA revenue requirement of $2.189 billion for 2004. The rate changes associated with the approved interim revenue requirement were effective as of September 1, 2004. The Utility's ERRA and related account balances for 2004 are subject to further true-up based on the final decision on the Utility's 2004 ERRA revenue requirement, which is expected during the fourth quarter of 2004. In addition, in the Utility's 2005 ERRA application filed in June 2004, the Utility requested authority to amortize routine over and under-collections in the ERRA annually to coincide with January 1 rate changes. A final decision on the 2005 ERRA application, in which the Utility requested a revenue requirement of $2.140 billion, is expected by the end of 2004.

Although the CPUC has no authority to review the reasonableness of procurement costs in the DWR's contracts, it may review the Utility's administration of the DWR allocated contracts. The Utility is required to dispatch its electricity resources, including the DWR allocated contracts, on a least-cost basis. The CPUC has established a maximum annual procurement disallowance for the Utility's administration of the DWR allocated contracts and least-cost dispatch of its electricity resources of two times the Utility's administration costs of managing procurement activities, or $36 million for 2004. Activities excluded from the maximum annual disallowance include fuel expenses for the Utility's electricity generation resources and contract administration costs associated with electricity procurement contracts, qualifying facility contracts and certain electricity generation expenses. It is uncertain whether the CPUC w ill modify or eliminate the maximum annual disallowance for future years. In the LTP, the Utility has requested that the CPUC clarify that the disallowance cap applies to both the allocated DWR contracts and administrative and dispatch costs related to utility-owned generation and other power purchase agreements.

The Utility and the CPUC's Office of Ratepayer Advocates, or the ORA, have agreed that there should be no disallowances in the Utility's ERRA proceeding reviewing procurement activities during the period from January 1, 2003 through December 31, 2003 and have jointly recommended that the CPUC close the record period. The Utility cannot predict whether a disallowance will result based on information reviewed or audited by the ORA in future ERRA filings or the size of any potential disallowance. In October 2004, the CPUC issued a draft resolution on the Utility's 2003 quarterly short-term procurement transaction compliance filings concluding that the Utility's procurement transactions are in compliance with its CPUC approved 2003 Short-Term Procurement Plan.

In addition, the CPUC may require the Utility or the Utility may elect to satisfy all or a part of its 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 the Utility to issue additional debt, which the Utility may not be able to issue on reasonable terms, or at all. In addition, if the Utility is not able to recover a material part of the cost of developing or acquiring additional generation facilities in rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

The Utility's LTP assumes that power plants currently providing 2,000 megawatts, or MW, of generation to the Utility will retire within the next five or six years. The Utility has requested that the CPUC approve the Utility's solicitation of offers for utility-owned generation development and for generation to be provided under long-term contracts for approximately 1,200 MW of peaking resources by 2008 and an additional 1,000 MW of load-following resources by 2010. The Utility released drafts of these two requests for offers, or RFOs, for comment in October 2004 and will issue the RFOs in November 2004. The Utility has requested that the CPUC issue a decision on its LTP by the end of 2004 and that the CPUC act to approve the proposed winning bidders from the RFOs no later than June 2005. The Utility also has requested that, at the time the CPUC approves an award for the turnkey development of a new utility-owned generation facility, the CPUC also authorize a reasonable cost for the facility to be placed into rate base. After consideration of new customer energy efficiency programs, an increase in purchase of renewable energy (as further discussed below), and a portfolio of short and medium term power purchase contracts, the Utility's target over the 10-year planning horizon is to own 50% of the new generation resources to be developed, with the remaining 50% of such resources to be purchased under long-term contracts of 5 to 20 years duration.

In the LTP filing, the Utility has requested that the CPUC adopt a policy that recognizes and addresses the fact that credit rating agencies will consider obligations under long-term power purchase contracts to have debt-like characteristics that will adversely affect the Utility's credit ratios which may, in turn, adversely affect the resulting credit ratings. The Utility has proposed that the CPUC evaluate the "debt equivalence" impacts when the Utility and the CPUC evaluate the bids for various long-term commitments and that the CPUC mitigate the resulting debt equivalence impacts in subsequent cost of capital proceedings through adjustments to the Utility's authorized capital structure.

In addition, to minimize the uncertainties regarding the level of future retail load the Utility will serve, the Utility has requested that the CPUC establish five-year resource adequacy requirements for all non-utility load serving entities, or LSEs, that will ensure that these entities secure reliable electricity supplies for all of their customers far enough in advance to avoid a statewide shortage of power. Also, to assure recovery of the Utility's costs of new long-term electricity resource commitments, the Utility has requested the CPUC adopt a non-bypassable charge to be collected from all customers on whose behalf the Utility makes these new commitments, including those who subsequently receive generation from LSEs.

The Utility also has proposed:

New customer energy efficiency, or CEE, programs to reduce load with total potential expenditures of approximately $1 billion over the 10-year planning horizon. To achieve the assumed load reductions, the Utility has requested that the CPUC approve an incremental revenue requirement increase of $245 million for three additional years (2006 through 2008) of CEE programs based on the targets as proposed in the LTP. The Utility also has requested that the CPUC approve a CEE incentive mechanism to encourage program success in achieving the proposed CEE targets.

The development of demand response programs in conjunction with the ISO that will result in certain, predictable load reductions.

In the LTP filing the Utility has assumed, under a medium load scenario, that by 2014, its procurement responsibility would be reduced by approximately 4,000 MW through a combination of (1) the continuation of current direct access levels, (2) a core/non-core program to be implemented through future legislation authorizing larger customers to participate in direct access on a phased-in basis starting as early as 2007, and (3) robust participation among smaller customers in community choice aggregation starting as early as 2006.

The CPUC has issued a schedule indicating that a decision on the Utility's LTP should be issued by the end of 2004. The Utility cannot predict the ultimate outcome of this matter.

On October 28, 2004, the CPUC voted to accelerate the electricity planning reserve requirement it established in January 2004. Under the accelerated schedule, California investor-owned electric utilities are required to achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006. The previous deadline was January 1, 2008. This accelerated phase-in will increase the amount of the electric resource commitments that the Utility would be required to make.

The California Governor has suggested that the requirement for each California investor-owned electric utility to 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, be amended to reach the 20% goal by 2010 instead. The California Senate has introduced a bill reaffirming the proposed accelerated requirement. In the LTP, the Utility estimates that it will achieve the proposed requirement of purchasing 20% of its retail sales from renewable resources by 2010 under the medium load scenario. Since the Utility is currently on target to meet these proposed recommendations, if this Senate bill is ultimately passed and approved by the CPUC, the Utility does not expect that the recommendations will have a material impact on the Utility's future operations.

California Energy Crisis Proceedings

FERC Proceedings

Various entities, including the Utility and the state of California, are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers from January 2000 to June 2001 through a proceeding pending at the FERC. This FERC proceeding, the "Refund Proceeding," commenced on August 2, 2000 when a complaint was filed against all suppliers in the markets operated by the ISO and the California Power Exchange, or the PX. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the amount of the overcharges that will be refunded. The FERC asserted that it would not order refunds for periods before October 2, 2000, because under a federal statute it can only order refunds beginning 60 days after a complaint for overcharges was filed and the first complaint for overcharges was not filed with the FERC until August 2 , 2000. In December 2002, a FERC ALJ issued an initial decision in the Refund Proceeding 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, but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

In March 2003, the FERC confirmed most of the ALJ's findings in the Refund Proceeding, 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 the first quarter of 2005. The PX cannot make its compliance filing until after the ISO has made its filing. In October 2003, the FERC affirmed its March 2003 decision. Various parties have filed appeals with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, of the variou s FERC orders in the Refund Proceeding. Although the Ninth Circuit originally held those appeals in abeyance while the FERC process continued, on October 22, 2004, the Ninth Circuit ordered that the appeals should proceed. According to a schedule being developed by the Ninth Circuit, the parties are required to submit briefs by March 2005 to address the issues of which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds.

El Paso Settlement

In June 2003, the Utility, along with SCE, the state of California and a number of other parties, entered into a settlement agreement with El Paso Natural Gas Company, or El Paso, 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 California energy crisis. In October 2003, the CPUC approved an allocation of these settlement proceeds. The Utility's natural gas customers would receive approximately $80 million and its electricity customers would receive approximately $215 million of the settlement proceeds over the next 15 to 20 years. In December 2003, the Utility recorded a receivable and corresponding regulatory liability of approximately $200 million for the discounted present value of the future payments. The El Paso settlement became effective in June 2004, at which ti me El Paso made upfront payments totaling approximately $568 million to all parties to the settlement agreement. The Utility's share of El Paso's $568 million upfront payment was approximately $25 million for its natural gas customers and approximately $70 million for its electricity customers. The remaining payments will be made in equal semi-annual installments over the next 15 to 20 years.

Enron Settlement

Williams Settlement

Dynegy Settlement

Duke Settlement

Natural Gas Supply and Transportation

On August 27, 2004, the Utility and all other active parties in the Utility's gas transmission and storage 2005 rate case, including The Utility Reform Network, or TURN, and the ORA filed a joint motion with the CPUC seeking approval of a proposed comprehensive settlement agreement, or the Gas Accord III Settlement. If approved by the CPUC, the proposed settlement will, among other things, set the Utility's gas transmission and storage rates and market structure for a three-year term, commencing January 1, 2005. The proposed settlement agreement would maintain the current Gas Accord market structure and service options.

The proposed settlement agreement provides a gas transmission and storage revenue requirement of approximately $428.5 million for 2005 and a two percent per year increase for the following two years. For the year 2006, the revenue requirement would be approximately $436.6 million, and for the year 2007, the revenue requirement would be approximately $444.9 million. The proposed settlement agreement also provides that the Utility should file its next gas transmission and storage rate case application no later than February 9, 2007, for rates to be in effect by January 1, 2008.

No comments were received by the CPUC in opposition to the settlement. A final decision is expected before the end of the year. PG&E Corporation and the Utility are unable to predict the ultimate outcome of this proceeding.

FERC Transmission Rate Cases

In January and October 2003, the Utility filed applications with the FERC requesting authority to recover its annual electricity transmission retail revenue requirements for 2003 and 2004. During the third quarter of 2004, the FERC issued final orders on these applications, which did not have a material impact on the Utility's 2004 results of operations. The current approved rates will remain in effect until the Utility's next rate application.

Electric Restructuring Costs Account Application

On April 16, 2004, the Utility filed an updated Electric Restructuring Costs Account application for recovery of distribution related electric industry restructuring related revenue requirements totaling $117 million for the period 1999 through 2002. Revenue requirements associated with these ongoing activities in 2003 and afterwards are included in the 2003 GRC, discussed above. The Settlement Agreement requires timely resolution of this proceeding by the CPUC.

The Utility has requested that the $117 million revenue requirement increase become effective January 1, 2005 and be recovered through the Distribution Revenue Adjustment Mechanism.

A proposed settlement agreement to resolve issues in this proceeding was reached between the Utility, ORA, Aglet Consumer Alliance, and TURN and submitted to the CPUC for approval on August 13, 2004. Under the proposed settlement agreement, the Utility would be authorized to collect $80 million in revenue requirements to recover the distribution related electric industry restructuring costs through rates charged to certain of the Utility's customers beginning January 1, 2005. Additionally, beginning January 1, 2007, the Utility would remove from rate base all remaining net plant in service associated with the Utility's capital plant at issue in this application, projected to be approximately $30 million at the end of 2006. If the CPUC approves the proposed settlement, the Utility would record a net pre-tax regulatory asset of approximately $50 million, resulting in an increase of approximately $30 million in after - -tax net income. The Utility has not recorded a regulatory asset for the costs it has incurred as of September 30, 2004 since these costs did not meet the applicable accounting probability standard under SFAS No. 71. A final decision is expected before the end of the year. PG&E Corporation and the Utility are unable to predict the ultimate outcome of this proceeding.

Diablo Canyon Steam Generator Replacement Projects

In connection with the Utility's efforts to replace turbines and steam generators and other equipment at the two nuclear operating units at the Utility's Diablo Canyon nuclear power plant, or Diablo Canyon, in 2003, the Utility established a steam generator replacement project for each unit. These projects include the procurement of replacement steam generators, the work to remove and replace the steam generators during planned refueling outages, and the project management and support for the approximately five year effort. The procurement of replacement steam generators has a long lead time, requiring about 40 months for delivery to Diablo Canyon. Therefore, the Utility entered into contracts with Westinghouse Electric Company LLC, or Westinghouse, in August 2004, for the design, fabrication and delivery of eight steam generators. The Utility plans to replace Unit 2's steam generators in 2008 and to replace Unit 1's steam generators in 2009. Under the contracts the Utility must pay for all work done and pro-rated profit up to the time the contracts are completed or cancelled. The contracts require progress payments in line with actual expenditures for materials and work completed over the life of the contracts. These payments are included in the projects' overall cash flow shown below.

In January 2004, the Utility filed an application with the CPUC seeking approval of the projects and authorization to recover the projected $706 million capital expenditures in rates. The CPUC has indicated that it will issue an interim opinion on the cost benefits of the projects in the first quarter of 2005 to support proceeding with the initial investments required to maintain a 2008/2009 implementation schedule, and a final decision, including incorporation of the environmental impact review for the projects in September 2005. In order to maintain the 2008 and 2009 steam generator replacement schedule required to coordinate Diablo Canyon's steam generator replacement outages with similar replacements being performed at San Onofre, the other large nuclear generating station serving California, initial expenditures on the contracts discussed above of approximately $25 million are expected to be incurred prior to receiving the CPUC's interim opinion. If the CPUC does not approve the projects, then the Utility will seek recovery of incurred project-costs. These costs would include: costs of design and procurement at cancellation, costs of engineering and project management up to cancellation, and all costs associated with the CPUC application process. The Utility would seek recovery of these costs through the abandoned project process. The cash flow for the project is shown below.

(in millions)

2004	$	25
2005	74
2006	124
2007	144
2008	204
Thereafter	135

Total	$	706

Spent Nuclear Fuel Storage Proceedings

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The Utility has signed a contract with the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste from the Utility's nuclear power facilities. Under the Utility's contract with the DOE, if the DOE completes a storage facility by 2010, the earliest that Diablo Canyon's spent fuel would be accepted for storage or disposal would be 2018. At the projected level of operation for Diablo Canyon, the Utility's current facilities are able to store on-site all spent fuel produced through approximately 2007. Therefore, the Utility applied to the NRC for authorization to build an on-site dry cask storage facility to store spent fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2. After conducting hearings on the request, the NRC granted authorization o n March 22, 2004. However, several intervenors in that proceeding filed an appeal of the NRC's decision in the Ninth Circuit. Oral arguments on that appeal are expected in the last quarter of 2004 with a decision anticipated in the first half of 2005. Under the California Coastal Act, the Utility is also required to obtain authorization to build the on-site dry cask storage facility from the county where the facility would be located. On April 20, 2004, San Luis Obispo County issued a permit to the Utility that contained a number of conditions. The Utility, along with several other interested parties, has filed appeals of the permit with the California Coastal Commission. Those appeals are expected to be decided by the end of 2004. As a contingency, the Utility will file in November 2004 to pursue NRC approval of another storage option to install a temporary storage rack in each unit that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. This temporary option would not require local or California Coastal permission permits to be implemented. During this additional period of time, if the dry cask storage has not yet been built, the Utility also could pursue NRC approval for a high density reracking of both units, which, if approved, would allow the Utility to operate both units until shortly before the licenses expire in 2021 for Unit 1 and 2024 for Unit 2. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility, and is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2007 and until such time as additional spent fuel can be safely stored.

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

In May 2004, 2003, 2002, 2001, and 2000, the Utility filed its annual applications with the CPUC claiming incentives totaling approximately $113 million in the Annual Earnings Assessment Proceeding for past energy efficiency program activities. These applications remain subject to verification and approval by the CPUC. The CPUC has authorized the Utility to recognize only an insignificant amount of these incentives in its results of operations. There are also a number of forward-looking proceedings regarding program administration and potential new incentive mechanisms for energy efficiency. The Utility considers that it is too early to predict whether the CPUC will allow it to continue administering energy efficiency programs and earning incentives based on the performance of the programs.

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations, financing arrangements, the marketplace for electricity, natural gas, electricity transmission, natural gas transportation and storage, other goods and services, and other aspects of their business. PG&E Corporation and the Utility categorize market risks as price risk, interest rate risk and credit risk. The Utility actively manages 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. The Utility's risk management activities include the use of energy and financial derivative instr uments, including forward contracts, futures, swaps, options, and other instruments and agreements.

The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility uses derivative instruments to manage the risks associated with ownership of assets, liabilities, committed transactions or probable forecasted transactions, or for complying with and managing risks associated with regulatory programs. The Utility enters 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. 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.

The Utility estimates 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, the Utility uses models to estimate fair value.

Price Risk

Convertible Subordinated Notes

In accordance with SFAS No. 133. "Accounting for Derivative Instruments and Hedging Activities," or SFAS No. 133, the dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be bifurcated from the Convertible Notes and marked to market on PG&E Corporation's Consolidated Statements of Income as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation's Consolidated Balance Sheets as a non-current liability (in Non-Current Liabilities - Other). At September 30, 2004, the estimated fair value of the dividend participation rights component was approximately $70 million, an increase in value of approximately $3 million, net of taxes, from June 30, 2004, and a year-to-date increase of approximately $41 million, net of taxes, for the nine-month period ended September 30, 2004.

Electricity

The Utility relies on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts and its own electricity generation facilities. In addition, the Utility purchases electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to one year ahead).

It is estimated that the residual net open position (the amount of electricity needed to meet the demands of customers, plus applicable reserve margins, that is not satisfied from the Utility's own generation facilities, purchase contracts or DWR contracts allocated to the Utility's customers) will change over time for a number of reasons, including:

·	Periodic expirations of existing electricity purchase contracts, or entering into new electricity purchase contracts;
·	Changes in the Utility's customers' electricity demands due to customer and economic growth and weather, and implementation of new energy efficiency and demand response programs, community choice aggregation, and a core/noncore retail market structure;
·	Planning reserve and operating requirements;
·	The reallocation of the DWR power purchase contracts among California investor-owned electric utilities; and
·	The retirement or other closure of the Utility's generation facilities.

In addition, unexpected outages at the Utility's generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility's residual net open position. The Utility expects to satisfy at least some of the residual net open position through new contracts. In July 2004, the Utility submitted its long-term integrated energy resource plan, or LTP, for the 2005 through 2014 period to the CPUC. In this LTP, to meet its net open position, the Utility proposes:

·	Entry into short- and mid-term power purchase agreements over the next four years with existing market resources to ensure adequate supply of electricity in the period before new generation facilities are assumed to become operational. The Utility has requested immediate authority from the CPUC to execute short and mid- term contracts under its existing short-term procurement plan.
·	The development of new utility-owned generation and generation to be purchased under long-term contracts particularly for the period of 2008 to 2010 when it is assumed that there will first be a need for additional generation facilities.
·	An increase in the percentage of renewable energy resources in the Utility's generation portfolio in accordance with the objective adopted in Senate Bill 1078. The LTP medium load scenario forecasts that by 2010, 20% of the Utility's retail load will be met by a combination of purchases from renewable energy providers and the re-powering of existing wind projects.

The Settlement Agreement provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs. In addition, California law requires that the CPUC review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually through 2006 and adjust retail electricity rates, or order refunds when there is an under- or over-collection exceeding 5% of the Utility's prior year electricity procurement revenues, excluding the revenue collected on behalf of the DWR. In addition, the CPUC has established a maximum procurement disallowance of approximately $36 million for the Utility's administration of the DWR contracts and least-cost dispatch. Adverse market price changes are not expected to impact the Utility's net income, while these cost recovery regulatory mechanisms remain in place. However, the Utility is at risk to the extent that the CP UC may in the future disallow transactions. Additionally, market price changes could impact the timing of the Utility's cash flows.

Nuclear Fuel

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

Nuclear fuel purchases are subject to tariffs of up to 8% on imports from certain countries. The Utility's nuclear fuel costs have not increased based on the imposed tariffs because the terms of the Utility's existing long-term contracts do not include these costs. However, these contracts begin to expire in 2004, and prices under new contracts may be higher as a result of such tariffs. In addition, because of an increase in U.S. demand for uranium compared with the domestic supply, uranium prices are trending higher in 2004.

As the Utility replaces existing contracts ending in 2004, new higher priced uranium contracts will raise nuclear fuel costs. The Utility is expected to partially offset these higher prices with reduced costs for other nuclear fuel components. These costs are recovered in ERRA (see the "Electricity Resources" section of this MD&A); therefore, the changes in nuclear fuel prices are not expected to materially impact net income.

Natural Gas

The Utility enters into physical and financial natural gas commodity contracts of up to one and one-half years in length to fulfill the needs of its retail core customers. Changes in temperature cause natural gas demand to vary daily, monthly and seasonally. Consequently, significant volumes of gas may be purchased in the spot market. The Utility's cost of natural gas includes the cost of Canadian and interstate transportation of natural gas purchased for its core customers.

Under the Core Procurement Incentive Mechanism, the Utility's purchase costs for a twelve month period 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 the Utility typically purchases 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 the Utility's customers receive, in their rates, three-fourths of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. 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

The Utility currently faces price risk for the portion of intrastate natural gas transportation capacity that is not contracted under fixed reservation charges used by core customers. Non-core customers contract with the Utility for natural gas transportation and storage, along with natural gas parking and lending (market center) services. The Utility is 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. The Utility sells most of its pipeline capacity based on the volume of natural gas that is transported by its customers. As a result, the Utility's natural gas transportation revenues fluctuate.

The Utility uses value-at-risk to measure the expected maximum change over a one-day period in the 18-month forward value of its transportation and storage portfolio. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the portfolio will incur a change in value in one day at least as large as the reported value-at-risk. For example, if the value-at-risk is calculated at $5 million, there is a 95% probability that if prices moved against current positions, the change in the value of the portfolio resulting from a one-day price movement would not exceed $5 million. The value-at-risk provides an indication of the Utility's exposure to potential market conditions that could impact revenues based on one-day price changes. It is also a way to measure the effectiveness of hedge strategies on a portfolio.

The Utility's value-at-risk for its transportation and storage portfolio was approximately $4.2 million at September 30, 2004 and approximately $6.0 million at September 30, 2003. A comparison of daily values-at-risk is included in order to provide context around the one-day amounts. The Utility's high, low and average transportation and storage value-at-risk during the first nine months of 2004 were approximately $6.4 million, $1.9 million and $3.5 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, mismatch of one-day liquidation period assumed in the value-at-risk methodology as compared to the longer term holding period of the storage and transportation portfolio, and inadequate indication of the exposure of a portfolio to extreme price movements. In addition, value-at-risk does not measure intra-day risk from position changes nor does it measure volumetric uncertainty in the demand for pipeline services.

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 PG&E Corporation and the Utility 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 September 30, 2004, if interest rates changed by 1% for all current variable rate debt held by PG&E Corporation and the Utility, the change would affect net income by an immaterial amount, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if customers or counterparties failed to perform their contractual obligations.

PG&E Corporation had gross accounts receivable of approximately $2.0 billion at September 30, 2004 and approximately $2.5 billion at December 31, 2003. The majority of the accounts receivable were associated with the Utility's residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately $63 million at September 30, 2004 and approximately $68 million at December 31, 2003 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. The Utility has a regional concentration of credit risk associated with its 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.

Credit exposure for the Utility's wholesale customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure, which could include obtaining additional collateral, or both. Further, the Utility relies 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.

The Utility calculates gross credit exposure for each of its wholesale 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 the first nine months of 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At September 30, 2004, there were two counterparties that represented greater than 10% of the Utility's net wholesale credit exposure. These two investment grade counterparties represented a total of approximately 46% of the Utility's net wholesale credit exposure.

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 the financial position and results of operations of PG&E Corporation and the Utility, 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.

Regulatory Assets and Liabilities

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No. 71. "Accounting for the Effects of Certain Types of Regulation," or SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the cost of providing service. SFAS No. 71 applies to all of the Utility's operations except for the operations of a natural gas pipeline. During the first quarter of 2004, the Utility began reapplying SFAS No. 71 to its generation 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, ALJ proposed decisions, final regulatory orders and the strength or status of applications for regulatory rehearings or state court appeals. The Utility also maintains regulatory balancing accounts, which are comprised of sales and cost balancing accounts. These balancing accounts are used to reco rd the differences between revenues and costs 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 September 30, 2004, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of approximately $7.5 billion and regulatory liabilities (including current balancing accounts payable) of approximately $4.4 billion.

Unbilled Revenues

The Utility records 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. As a result of CPUC decisions approving the Settlement Agreement and implementing various ratemaking mechanisms, the Utility no longer records frozen electric rates and surcharges directly to earnings as it had in 2003. Instead, the Utility collects cost-of-service based electric rates that are the sum of specific revenue requirements. As a result, changes in unbilled revenues no longer have a material impact on the Utility's results of operations.

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. The Utility records a liability associated with environmental remediation activities when it is determined that remediation is probable and the 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 September 30, 2004, the Utility's accrual for undiscounted environmental liability was approximately $342 million. The Utility's undiscounted future costs could increase to as much as $464 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.

TAXATION MATTERS

The IRS has completed its audit of PG&E Corporation's 1997 and 1998 consolidated federal income tax returns and has assessed additional federal income taxes of approximately $77 million (including interest). PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and currently is discussing these adjustments with the IRS' Appeals Office. PG&E Corporation does not expect final resolution of these appeals to have a material impact on its financial position or results of operations.

The IRS has completed its audit of PG&E Corporation's 1999 and 2000 consolidated federal income tax returns during the third quarter of 2004 and has assessed additional taxes. Since PG&E Corporation made an advance payment to the IRS of $75 million in the fourth quarter of 2003, no additional tax payment is due to the IRS. Settlement of this audit does not have a material impact on PG&E Corporation's financial position or result of operations.

The IRS is auditing PG&E Corporation's 2001 and 2002 consolidated federal income tax returns. In September 2004, the IRS issued notices of proposed adjustments that propose to disallow $104 million of synthetic fuel credits claimed on these tax returns. In addition, the IRS has proposed to disallow abandonment losses deducted on the 2002 tax return related to certain NEGT assets. These assets were transferred to NEGT lenders in the third quarter of 2004. In addition, the IRS has challenged other deductions related to NEGT prior to its Chapter 11 filing. PG&E Corporation is disputing the IRS's proposed adjustments and will contest these disallowances if the IRS continues to assert its current position. PG&E Corporation has accrued $52 million associated with NEGT related tax liabilities. Considering this reserve, PG&E Corporation does not expect the resolution of these matters to have a materia l impact on its financial position or result of operations.

All IRS audits of PG&E Corporation's federal income tax returns prior to 1997 have been closed. In addition, certain other state tax authorities are currently auditing various state tax returns.

Prior to July 8, 2003, the date that NEGT filed for bankruptcy protection, PG&E Corporation recognized federal income tax benefits related to the losses of NEGT and its subsidiaries. However, after July 7, 2003, PG&E Corporation has not recognized additional income tax benefits for financial reporting purposes with respect to the losses of NEGT and its subsidiaries even though it must continue to include NEGT and its subsidiaries in its consolidated income tax returns. After its equity ownership in NEGT is cancelled on the effective date of NEGT's plan of reorganization, PG&E Corporation will no longer include NEGT or its subsidiaries in its consolidated income tax returns. In addition, any remaining deferred tax assets related to NEGT or its subsidiaries, will be reversed in discontinued operations in the Consolidated Statements of Operations at the time PG&E Corporation's equity interest in NEGT is cancelled. On October 29, 2004, NEGT's plan of reorganization under Chapter 11 became effective, at which time NEGT emerged from Chapter 11. PG&E Corporation's equity ownership in NEGT was cancelled on the effective date of NEGT's plan of reorganization.

In addition to the reversal of deferred tax assets referred to above, and based on preliminary information provided by NEGT, PG&E Corporation anticipates paying approximately $94 million of consolidated tax obligations in 2004 attributable to NEGT's estimated taxable income through the effective date of NEGT's plan of reorganization.

PG&E Corporation and NEGT have entered into a separate agreement under which they have agreed to take certain actions and cooperate with each other with respect to certain tax matters, including future tax returns and audits. This litigation is discussed further in Note 6 of the Notes to the Consolidated Financial Statements.

For the nine-month period ended September 30, 2003, PG&E Corporation increased its valuation allowances against certain state deferred tax assets related to NEGT or its subsidiaries due to the uncertainty of their realization. During this period, valuation allowances of approximately $24 million were recorded in discontinued operations, and approximately $5 million was recorded in accumulated other comprehensive loss. No valuation allowances were recorded in the three-month period ended September 30, 2003 or during 2004.

ADDITIONAL SECURITY MEASURES

Various federal regulatory agencies have issued guidance and the NRC has issued orders regarding additional security measures to be taken at various facilities, including generation facilities, transmission substations and natural gas transportation facilities. The guidance and the orders require additional capital investment and increased operating costs. However, neither PG&E Corporation nor the Utility believes that these costs will have a material impact on its consolidated financial position or results of operations.

ENVIRONMENTAL AND LEGAL MATTERS

PG&E Corporation and the Utility are subject to laws and regulations established both to maintain and improve the quality of the environment. Where PG&E Corporation's and the Utility's properties contain hazardous substances, these laws and regulations require PG&E Corporation and the Utility to remove those substances or to remedy effects on the environment. Also, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. See Note 6 of the Notes to the Consolidated Financial Statements for further discussion of environmental matters and significant pending legal matters.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation's and Pacific Gas and Electric Company's, or the Utility's, primary market risk results from changes in energy prices. PG&E Corporation and the Utility engage in price risk management, or PRM, activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these PRM activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. (See the "Risk Management Activities" section included in Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations.)

ITEM 4: CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation's and Pacific Gas and Electric Company's, or the Utility's, disclosure controls and procedures as of September 30, 2004, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports the companies file or submit under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

As of January 1, 2004, PG&E Corporation and the Utility adopted the Financial Accounting Standards Board's, or FASB, revision to FASB Interpretation No. 46, "Consolidation of Variable Interest Entities," or FIN 46R. In accordance with FIN 46R, the Utility consolidated the assets, liabilities and non-controlling interests of low-income housing partnerships that were determined to be variable interest entities, or VIEs, under FIN 46R. PG&E Corporation and the Utility do not have the legal right or authority to assess the internal controls of VIEs. Therefore, PG&E Corporation and the Utility's evaluation of disclosure controls and procedures performed as of September 30, 2004, did not include these entities in that evaluation. PG&E Corporation and the Utility have not designed, established, or maintained disclosure controls and procedures for consolidated VIEs.

There were no changes in internal controls over financial reporting that occurred during the quarter ended September 30, 2004, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For additional information regarding certain of the legal proceedings presented below, see Note 6 of the Notes to the Condensed Consolidated Financial Statements.

Pacific Gas and Electric Company Chapter 11 Filing

Pacific Gas and Electric Company's, or the Utility's, Chapter 11 proceeding has been previously disclosed in PG&E Corporation's and the Utility's combined 2003 Annual Report on Form 10-K in "Part I, Item 3: Legal Proceedings" and in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarterly periods ended March 31 and June 30, 2004 under Part II, Item 1: Legal Proceedings." For additional information, see Note 2 of the Notes to the Consolidated Financial Statements.

Chapter 11 Filing of NEGT

On October 29, 2004, NEGT's plan of reorganization became effective and PG&E Corporation's equity interest in NEGT was cancelled. For more information regarding this matter, see PG&E Corporation's and the Utility's combined 2003 Annual Report on Form 10-K, in "Part I, Item 3: Legal Proceedings" and Note 4 of the Notes to the Consolidated Financial Statements.

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

For information regarding this matter, see "Part I, Item 3: Legal Proceedings - Pacific Gas and Electric Company vs. Michael Peevey, et al." in PG&E Corporation's and the Utility's combined 2003 Annual Report on Form 10-K and PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004 under Part II, Item 1: Legal Proceedings."

In re: Natural Gas Royalties Qui Tam Litigation

For information regarding this matter, see "Part I, Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2003 Annual Report on Form 10-K.

Diablo Canyon Power Plant

For information regarding matters relating to the Diablo Canyon Power Plant, see PG&E Corporation's and the Utility's combined 2003 Annual Report on Form 10-K, and "Part II, Item 1: Legal Proceedings" of PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004.

Compressor Station Chromium Litigation

For information regarding the chromium litigation, see "Part I, Item 3: Legal Proceedings - Compressor Station Chromium Litigation" in PG&E Corporation's and the Utility's combined 2003 Annual Report on Form 10-K, and "Part II, Item 1: Legal Proceedings - Compressor Station Chromium Litigation" in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2004.

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

As previously disclosed, in approving PG&E Corporation's formation as the holding company of the Utility, the California Public Utilities Commission, or the CPUC, imposed certain conditions, including an obligation by PG&E Corporation's Board of Directors to give "first priority" to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve and to operate in a prudent and efficient manner. The CPUC later issued decisions in which it adopted an expansive interpretation of holding companies' obligations under this condition, including the requirement that each of the holding companies "infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve." The CPUC also asserted that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similar holding companies. PG&E Corpo ration and the holding companies of the other major California investor-owned electric utilities appealed these decisions. On May 21, 2004, the California Court of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding companies to enforce the conditions imposed by the CPUC when the CPUC authorized the formation of the holding companies, but that the CPUC's decision interpreting the capital requirements condition was not ripe for review. PG&E Corporation appealed the decision of the California Court of Appeal finding that the CPUC had limited jurisdiction to the California Supreme Court. On September 1, 2004, the California Supreme Court denied the petition.

With respect to the litigation pending in the San Francisco Superior Court, or the Superior Court, at a hearing on September 8, 2004, the Superior Court granted PG&E Corporation's request to bifurcate the trial on the issue of how to determine the standard to be applied in calculating the number of violations that plaintiffs allege have been committed. A trial on this issue has been scheduled for December 8, 2004. PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.

On October 22, 2004, Cynthia Behr dismissed with prejudice her lawsuit against PG&E Corporation and its directors, as well as the Utility's directors, in exchange for PG&E Corporation's waiver of costs in the matter.

For more information regarding these cases, see "Part I, Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2003 Annual Report on Form 10-K, and "Part II, Item 1: Legal Proceedings" of PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarterly periods ended March 31, 2004 and June 30, 2004.

ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS, AND ISSUER PURCHASES OF EQUITY SECURITIES

As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002, PG&E Corporation issued warrants to purchase 5,066,931 shares of common stock of PG&E Corporation at an exercise price of $0.01 per share. As of September 30, 2004, warrantholders had exercised, on a net exercise basis, warrants to purchase 3,757,539 shares, and had received 3,756,107 shares of PG&E Corporation common stock.

Issuer Purchases of Equity Securities

Period			Total Number of Shares Purchased ⁽¹⁾			Average Price Paid Per Share ⁽²⁾				Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ^{(3) (4)}				Approximate Dollar Value of Shares that may yet be Purchased Under the Plans or Programs

July 1 through July 31, 2004				150,000	$			25.410625				-	$		-
August 1 through August 31, 2004		-			-				-				-
September 1 through September 30, 2004		-			-				-				-

Total				150,000	$		25.410625				-		$		-






⁽¹⁾	On July 31, 2004, pursuant to a mandatory sinking fund redemption provision, the Utility redeemed 150,000 shares of its 6.57% Series of First Preferred Stock.
⁽²⁾	The redemption price includes any accumulated and unpaid dividends existing as of the redemption date.
⁽³⁾	On September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase price not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Repurchases may be made from time until the program expires on December 31, 2005.
⁽⁴⁾	Also on September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase up to $350 million in shares of PG&E Corporation's common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Any repurchase under this program may not be initiated until PG&E Corporation redeems the full $600 million aggregate principal amount of the Senior Secured Notes due 2008, which is expected to be on November 15, 2004. Repurchases may be made from time to time after this date until the program expires on December 31, 2005.

The description of the limitations on the payment of dividends by PG&E Corporation and the Utility contained in Part I, Management's Discussion and Analysis of Financial Condition and Results of Operations, in the section entitled "Dividends and Share Repurchases" is incorporated herein by reference.

ITEM 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

Pacific Gas and Electric Company, or the Utility's, earnings to fixed charges ratio for the three months ended September 30, 2004, was 3.72. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended September 30, 2004, was 3.51. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into the Utility's Registration Statement Nos. 33-62488 and 333-109994 relating to various series of the Utility's first preferred stock and its senior secured bonds, respectively.

ITEM 6. EXHIBITS

11	Computation of Earnings Per Common Share
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
* Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION

CHRISTOPHER P. JOHNS

Christopher P. Johns
Senior Vice President and Controller
(duly authorized officer and principal accounting officer)

PACIFIC GAS AND ELECTRIC COMPANY

DINYAR B. MISTRY

Dinyar B. Mistry
Vice President and Controller
(duly authorized officer and principal accounting officer)

Dated: November 2, 2004

EXHIBIT INDEX

11	Computation of Earnings Per Common Share
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
* Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.