Pacific Gas & Electric (PCG+A) 10-Q 2004 Q2 Quarterly report

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 June 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, July 28, 2004:
PG&E Corporation			400,906,760 shares (excluding 23,815,500shares 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 JUNE 30, 2004
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Operations		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Operations		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	22
	NOTE 3:		Debt	27
	NOTE 4:		Discontinued Operations	32
	NOTE 5:		Price Risk Management	33
	NOTE 6:		Commitments and Contingencies	35
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			46
	Results of Operations			54
	Liquidity and Financial Resources			59
	Capital Expenditures and Commitments			64
	Regulatory Matters			65
	Risk Management Activities			74
	Critical Accounting Policies			78
	Accounting Pronouncements Issued But Not Yet Adopted			79
	Taxation Matters			79
	Additional Security Measures			80
	Environmental and Legal Matters			80
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			81
ITEM 4.	CONTROLS AND PROCEDURES			81
PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS			82
ITEM 2.	CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER REPURCHASES OF EQUITY SECURITIES			83
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES			84
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			85
ITEM 5.	OTHER INFORMATION			85
ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K			86
SIGNATURES				89

PART I. FINANCIAL INFORMATION
ITEM 1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)					(Unaudited)
					Three months ended						Six months ended
					June 30,						June 30,
					2004		2003				2004				2003
Operating Revenues
		Electric			$	2,063	$		2,058	$		3,851		$		3,412
		Natural gas			686		656			1,617				1,484
				Total operating revenues	2,749		2,714			5,468				4,896
Operating Expenses
		Cost of electricity			685		562			1,254				1,152
		Cost of natural gas			278		306			857				777
		Operating and maintenance			757		721			1,576				1,435
		Recognition of regulatory assets			-		-			(4,900)				-
		Depreciation, amortization and decommissioning			353		288			651				598
		Reorganization professional fees and expenses			4		65			6				100
				Total operating expenses	2,077		1,942			(556)				4,062
Operating Income					672		772			6,024				834
		Reorganization interest income			-		17			8				27
		Interest income			25		5			31				7
		Interest expense			(176)		(260)			(406)				(515)
		Other expense, net			(14)		6			(41)				14
Income Before Income Taxes					507		540			5,616				367
		Income tax provision			135		212			2,211				122
Income From Continuing Operations					372		328			3,405				245
Discontinued Operations
	Loss from operations of NEGT
			(net of income tax benefit of $(65) million and $(221) million for the three and six months ended June 30, 2003)
					-		(101)				-				(366)
Net Income (Loss) Before Cumulative Effect of Changes					372		227			3,405				(121)
	in Accounting Principles
	Cumulative effect of changes in accounting principles
			of $(5) million in 2003 related to discontinued operations (net of income tax benefit $3 million) and $(1) related to continuing operations (net of income tax benefit of $1 million)		-		-				-				(6)
Net Income (Loss)					$	372	$	227		$		3,405		$		(127)
Weighted Average Common Shares Outstanding, Basic					397		384			395				383
Earnings Per Common Share
	from Continuing Operations, Basic				$	0.89	$		0.81		$		8.22		$		0.61
Net Earnings (Loss) Per Common Share, Basic					$	0.89	$	0.56		$		8.22		$		(0.32)
Earnings Per Common Share
	from Continuing Operations, Diluted				$	0.88	$		0.80		$		8.03		$		0.60
Net Earnings (Loss) Per Common Share, Diluted					$	0.88	$	0.55		$		8.03		$		(0.31)
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	June 30,		December 31,
	2004 (Unaudited)		2003
ASSETS
Current Assets
Cash and cash equivalents	$	1,420	$	3,658
Restricted cash	2,144		403
Accounts receivable:
Customers (net of allowance for doubtful accounts of $58 million        in 2004 and $68 million in 2003)	2,034		2,424
Related parties	-		15
Regulatory balancing accounts	817		248
Inventories:
Gas stored underground	160		166
Materials and supplies	127		126
Prepaid expenses and other	42		108
Total current assets	6,744		7,148
Property, Plant and Equipment
Electric	20,924		20,468
Gas	8,465		8,355
Construction work in progress	388		379
Other	19		20
Total property, plant and equipment	29,796		29,222
Accumulated depreciation	(11,254)		(11,115)
Net property, plant and equipment	18,542		18,107
Other Noncurrent Assets
Restricted cash	361		361
Regulatory assets	6,811		2,001
Nuclear decommissioning funds	1,522		1,478
Other	1,103		1,109
Total other noncurrent assets	9,797		4,949
TOTAL ASSETS	$	35,083	$	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)	June 30,			December 31,
	2004 (Unaudited)			2003
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Long-term debt, classified as current	$		458	$	310
Current portion of rate reduction bonds	290			290
Accounts payable:
Trade creditors	528			657
Disputed claims	2,148			-
Regulatory balancing accounts	315			186
Other	463			402
Interest payable	439			174
Income taxes payable	540			256
Other	935			899
Total current liabilities	6,116			3,174
Noncurrent Liabilities
Long-term debt	8,728			3,314
Rate reduction bonds	729			870
Regulatory liabilities	3,997			3,979
Asset retirement obligations	1,259			1,218
Deferred income taxes	2,892			856
Deferred tax credits	123			127
Net investment in NEGT	1,220			1,216
Preferred stock of subsidiary with mandatory redemption provisions	126			137
Other	1,879			1,494
Total noncurrent liabilities	20,953			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)	-			-
Preferred Stock of Subsidiaries	286			286
Preferred Stock
Preferred stock, no par value, 80,000,000 shares, $100 par value,       5,000,000 shares, none issued	-			-
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares,        issued 423,479,604 common and 1,130,373 restricted shares in        2004 and 414,985,014 common and 1,535,268 restricted in 2003	6,579			6,468
Common stock held by subsidiary, at cost,23,815,500 shares	(690)			(690)
Unearned compensation	(27)			(20)
Accumulated earnings (deficit)	1,947			(1,458)
Accumulated other comprehensive loss	(81)			(85)
Total shareholders' equity	7,728			4,215
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	35,083		$	30,204
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)
	Six Months Ended
(in millions)	June 30,
	2004		2003
Cash Flows From Operating Activities
Net income (loss)	$	3,405	$	(127)
Loss from discontinued operations	-		366
Cumulative effect of changes in accounting principles	-		6
Net income from continuing operations	3,405		245
Adjustments to reconcile net income (loss) to net cash      provided by operating activities:
Depreciation, amortization and decommissioning	651		598
Recognition of regulatory assets	(4,900)		-
Deferred income taxes and tax credits, net	2,053		300
Other deferred charges and noncurrent liabilities	12		484
Gain on sale of assets	(18)		(7)
Net effect of changes in operating assets and liabilities:
Restricted cash	93		(199)
Accounts receivable - customer	(8)		84
Inventories	5		(42)
Accounts payable - trade	170		253
Accrued taxes	284		163
Regulatory balancing accounts, net	(440)		(190)
Other working capital	560		(156)
Payments authorized by the bankruptcy court on amounts classified as      liabilities subject to compromise	(1,022)		(62)
Other, net	(134)		30
Net cash provided by operating activities	711		1,501
Cash Flows From Investing Activities
Capital expenditures	(737)		(730)
Net proceeds from sale of assets	25		11
Increase in restricted cash	(1,834)		-
Other, net	(54)		12
Net cash used by investing activities	(2,600)		(707)
Cash Flows From Financing Activities
Net proceeds from issuance of long-term debt	6,892		-
Long-term debt matured, redeemed or repurchased	(7,098)		-
Rate reduction bonds matured	(141)		(141)
Preferred stock with mandatory redemption provisions redeemed	(11)		-
Dividends Paid	(88)		-
Common stock issued	97		54
Net cash provided (used) by financing activities	(349)		(87)
Net change in cash and cash equivalents	(2,238)		707
Cash and cash equivalents at January 1	3,658		3,532
Cash and cash equivalents at June 30	$	1,420	$	4,239
Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	11	$	21
Cash paid for:
Interest (net of amounts capitalized)		351		432
Income taxes paid, net		48		(531)
Reorganization professional fees and expenses		17		71
Supplemental disclosures of noncash investing and financing activities
Transfer of liabilities and other payables subject to compromise from
operating assets and liabilities		(2,877)		127
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
						(Unaudited)
						Three months ended				Six months ended
						June 30,				June 30,
						2004		2003		2004			2003
Operating Revenues
	Electric					$	2,063	$	2,058	$	3,851		$	3,412
	Natural gas					686		657		1,617			1,487
			Total operating revenues			2,749		2,715		5,468			4,899
Operating Expenses
	Cost of electricity					685		562		1,254			1,162
	Cost of natural gas					278		320		857			806
	Operating and maintenance					748		714		1,557			1,441
	Recognition of regulatory assets					-		-		(4,900)			-
	Depreciation, amortization, and decommissioning					352		307		650			605
	Reorganization professional fees and expenses					4		65		6			100
			Total operating expenses			2,067		1,968		(576)			4,114
Operating Income						682		747		6,044			785
	Reorganization interest income					-		17		8			27
	Interest income					23		3		26			4
	Interest expense (noncontractual interest expense of $0 and
				$31 million for the three and six months ended June 30, 2004, respectively, and $35 million and $67 million for the three and six months ended June 30, 2003, respectively)		(158)		(224)		(372)			(444)
	Other income, net					24		11		38			26
Income Before Income Taxes						571		554		5,744			398
	Income tax provision					159		209		2,258			125
Income Before Cumulative Effect of a Change in    Accounting Principle						412		345		3,486			273
		Cumulative effect of change in accounting principle
				(net of income tax benefit of $1 million for the six months ended June 30, 2003)		-		-		-			(1)
Net Income						412		345		3,486			272
	Preferred dividend requirement					4		6		12			12
Income Available for Common Stock					$		408	$	339	$		3,474	$	260
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
	Balance At
(in millions)	June 30,		December 31,
	2004 (Unaudited)		2003
ASSETS
Current Assets
Cash and cash equivalents	$	553	$	2,979
Restricted cash	2,144		403
Accounts receivable:
Customers (net of allowance for doubtful accounts of $58 million in 2004         and $68 million in 2003)	2,034		2,424
Related parties	3		17
Regulatory balancing accounts	817		248
Inventories:
Gas stored underground	160		166
Materials and supplies	127		126
Prepaid expenses and other	40		100
Total current assets	5,878		6,463
Property, Plant and Equipment
Electric	20,924		20,468
Gas	8,465		8,355
Construction work in progress	388		379
Total property, plant and equipment	29,777		29,202
Accumulated depreciation	(11,238)		(11,100)
Net property, plant and equipment	18,539		18,102
Other Noncurrent Assets
Regulatory assets	6,811		2,001
Nuclear decommissioning funds	1,522		1,478
Other	1,041		1,051
Total other noncurrent assets	9,374		4,530
TOTAL ASSETS	$	33,791	$	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)		June 30,		December 31,
		2004 (Unaudited)		2003
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Current portion of long-term debt		$	458	$	310
Current portion of rate reduction bonds		290		290
Accounts payable:
Trade creditors		528		657
Disputed claims		2,148		-
Related parties		45		224
Regulatory balancing accounts		315		186
Other		453		365
Interest payable		420		153
Income taxes payable		332		-
Deferred income taxes		106		86
Other		768		673
Total current liabilities		5,863		2,944
Noncurrent Liabilities
Long-term debt		7,845		2,431
Rate reduction bonds		729		870
Regulatory liabilities		3,997		3,979
Asset retirement obligations		1,259		1,218
Deferred income taxes		3,423		1,334
Deferred tax credits		123		127
Preferred stock with mandatory redemption provisions		126		137
Other		1,784		1,464
Total noncurrent liabilities		19,286		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 5,784,825shares	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	5,180			1,706
Accumulated other comprehensive loss	(3)			(6)
Total shareholders' equity	8,642			5,089
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$		33,791	$	29,095
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	(Unaudited)
	Six Months Ended
(in millions)	June 30,
	2004		2003
Cash Flows From Operating Activities
Net income	$	3,486	$		272
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and decommissioning	650		605
Recognition of regulatory assets	(4,900)		-
Deferred income taxes and tax credits, net	2,105		101
Other deferred charges and noncurrent liabilities	79		284
Gain on sale of assets	(18)		(7)
Cumulative effect of a change in accounting principle	-		1
Net effect of changes in operating assets and liabilities:
Restricted cash	93		(84)
Accounts receivable	(35)		84
Inventories	5		(42)
Accounts payable	170		252
Accrued taxes	288		51
Regulatory balancing accounts, net	(440)		(190)
Other working capital	287		(79)
Payments authorized by the bankruptcy court on amounts classified as liabilities      subject to compromise	(1,022)		(62)
Other, net	(128)		18
Net cash provided by operating activities	620		1,204
Cash Flows From Investing Activities
Capital expenditures	(737)		(730)
Net proceeds from sale of assets	25		11
Increase in restricted cash	(1,834)		-
Other, net	(54)		13
Net cash used by investing activities	(2,600)		(706)
Cash Flows From Financing Activities
Net proceeds from issuance of long-term debt	6,892		-
Long-term debt matured, redeemed or repurchased	(7,098)		-
Rate reduction bonds matured	(141)		(141)
Dividends paid	(88)		-
Preferred stock with mandatory redemption provisions redeemed	(11)		-
Net cash used by financing activities	(446)		(141)
Net change in cash and cash equivalents	(2,426)		357
Cash and cash equivalents at January 1	2,979		3,343
Cash and cash equivalents at June 30	$	553	$		3,700
Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	11	$		21
Cash paid for:
Interest (net of amounts capitalized)	315		341
Income taxes paid (refunded), net	-			32
Reorganization professional fees and expenses	17		71
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)		127
See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: GENERAL

Organization and Basis of Presentation

               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. Both PG&E Corporation and the Utility are headquartered in San Francisco, California.

               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. During its Chapter 11 proceeding, the Utility retained control of its assets and was authorized to operate its business as a debtor-in-possession.

               PG&E Corporation's other significant subsidiary is National Energy & Gas Transmission, Inc., formerly known as PG&E National Energy Group, Inc., or PG&E NEG, headquartered in Bethesda, Maryland.PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. On July 8, 2003, PG&E NEG and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. Subsequently, on July 29, 2003, two additional subsidiaries of PG&E NEG also filed voluntary Chapter 11 petitions. PG&E NEG and those subsidiaries in Chapter 11 retain control of their assets and are authorized to operate their businesses as debtors-in-possession while being subject to the jurisdiction of the bankruptcy court. On October 3, 2 003, the bankruptcy court authorized PG&E NEG to change its name to National Energy & Gas Transmission, Inc., or NEGT. The change reflects NEGT's pending separation from PG&E Corporation. Consequently, all subsequent references to PG&E NEG in these Notes to the Condensed Consolidated Financial Statements will refer to NEGT. On May 3, 2004, NEGT's plan of reorganization was confirmed by the bankruptcy court.When NEGT's plan of reorganization becomes effective, PG&E Corporation's equity interest in NEGT will be eliminated.

               Under accounting principles generally accepted in the United States of America, or GAAP, consolidation is generally required for investments of more than 50% of the outstanding voting stock of an investee, except when control is not held by the majority owner. Under these rules, 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 retains significant influence over the ongoing operations of NEGT. Effective July 8, 2003, PG&E Corporation no longer consolidates the earnings and losses of NEGT or i ts subsidiaries and has reflected its ownership interest in NEGT utilizing the cost method of accounting, 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. In addition, for the reasons described above, 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 (see Note 4 for further information).

               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 Condensed Financial Statements have been prepared in accordance with 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. 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 t hat are deemed probable from environmental remediation liabilities, pension liabilities, mark-to-market accounting under SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities,'' income taxes, and 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.

               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 combined 2003 Annual Report filed with the Current Report on Form 8-K dated June 18, 2004.

               During the period 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 June 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 June 30, 2004 condensed 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 combined 2003 Annual Report filed with the Current Report on Form 8-K dated June 18, 2004.

Participating Securities and the Two-Class Method

               On March 31, 2004, the Financial Accounting Standards Board, or FASB, ratified the consensus reached by its Emerging Issues Task Force, or 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 $280million 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.

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 $15 million for the LIHP have been included in the Utility's consolidated balance sheet. The consolidated LIHP has issued debt in the amount of $7 million, which is secured by assets of the partnership, totaling $28 million, and the Utility's commitment to make capital infusions of approximately $15 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 current investment balance of $6 million.

Power Purchase Agreements

               The Utility is unable to apply the provisions of FIN 46R to 25 entities that are counterparties of power purchase agreements. It is conceivable that the Utility could have a significant variable interest in a power purchase agreement counterparty if that entity is a variable interest entity and it owns 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. The Utility has requested, but not received, the information necessary to determine whether 25of its power purchase agreement counterparties are variable interest entities or determine if the Utility is the primary beneficiary of these entities because the counterparties are not legally required to provide the Utility with the information.

               These 25entities are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. Under PURPA, the CPUC required California investor-owned electric utilities to enter into a series of long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, price options and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility's actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility's total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement. In regards to these 25agreements, approxim ately 1,000megawatts, or MW, expire between 2004 and 2026 and approximately 71MW have no specific expiration dates. Collective purchases from these entities were $118million for the six months ended June 30, 2004 and $116million for the six months ended June 30, 2003. The Utility has no investment at risk in the counterparty entities or commitment to fund losses.

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 optionality.

               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 optionality 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 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 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)	June 30, 2004		December 31, 2003
Settlement regulatory assets	$	4,648	$	-
Rate reduction bond assets	912		1,054
Regulatory assets for deferred income tax	451		324
Unamortized loss, net of gain, on reacquired debt	358		277
Qualifying facilities restructuring costs	146		151
Environmental compliance costs	159		139
Financing costs	114		-
Other, net	23		56
Total regulatory assets	$	6,811	$		2,001

               Regulatory assets are 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 $2.2 billion, after-tax ($3.7 billion, pre-tax), regulatory asset established under the Settlement Agreement, or the Settlement Regulatory Asset, and $0.7 billion, after-tax ($1.2 billion, pre-tax), for the Utility retained generation regulatory assets in the first quarter of 2004 (see further discussion in "Note 2").

Regulatory Liabilities

               Regulatory liabilities comprise the following:

(in millions)	June 30, 2004		December 31, 2003
Cost of removal obligations	$	1,896	$	1,810
Employee benefit plans	782		925
Asset retirement costs	623		584
Public purpose programs	208		185
Rate reduction bonds	179		175
Surcharge liability	138		125
Other	171		175
Total regulatory liabilities	$	3,997	$	3,979

Regulatory Balancing Accounts

               Sales balancing accounts accumulate differences between billed and unbilled revenues and revenues the Utility is authorized to collect through 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				Six months ended
	June 30,				June 30,
(in millions, except per share amounts)	2004		2003		2004		2003
Income from continuing operations	$	372	$	328	$	3,405	$	245
Discontinued operations		-		(101)		-		(366)
Net income (loss) before cumulative effect of changes in    accounting principles		372	227		3,405		(121)
Cumulative effect of changes in accounting principles	-		-		-		(6)
Net Income (Loss) for basic and diluted calculations	$	372	$	227	$	3,405	$	(127)
Weighted average common shares outstanding, basic		397		384		395		383
9.5% Convertible Subordinated Notes		19		19		19		19
Weighted average common shares outstanding and    participating securities, basic		416		403		414		402
Weighted average common shares outstanding, basic		397		384		395		383
Employee stock options and PG&E Corporation shares held by    grantor trusts		7		2		7		1
PG&E Corporation Warrants		2		5		3		5
Weighted average common shares outstanding, diluted		406		391		405		389
9.5% Convertible Subordinated Notes		19		19		19		19
Weighted average common shares outstanding and    participating securities, diluted		425		410		424		408
Earnings (Loss) Per Common Share, Basic
Income from continuing operations	$	0.89	$	0.81	$	8.22	$	0.61
Discontinued operations		-		(0.25)		-		(0.91)
Cumulative effect of changes in accounting principles		-		-		-		(0.02)
Net earnings (loss)	$	0.89	$	0.56	$	8.22	$	0.32
Earnings (Loss) Per Common Share, Diluted
Income from continuing operations	$	0.88	$	0.80	$	8.03	$	0.60
Discontinued operations		-		(0.25)		-		(0.90)
Cumulative effect of changes in accounting principles		-		-		-		(0.01)
Net earnings (loss)	$	0.88	$	0.55	$	8.03	$	(0.31)

               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 9.5% Convertible Notes in the allocation of earnings. The 9.5% Convertible Notes are convertible at the option of PG&E Corporation into 18,558,655 common shares. All PG&E Corporation's participating securities participate on a 1:1 basis with common shareholders.

	Three months ended				Six months ended
	June 30,				June 30,
Earnings (loss) allocated to common shareholders, basic	2004		2003		2004		2003
Income from continuing operations	$	355	$	312	$	3,249	$	233
Discontinued operations		-		(96)		-		(349)
Cumulative effect of changes in accounting principles		-		-		-		(6)
	$	355	$	216	$	3,249	$	(122)
Earnings (loss) allocated to common shareholders, diluted
Income from continuing operations	$	356	$	312	$	3,252	$	234
Discontinued operations		-		(96)		-		(349)
Cumulative effect of changes in accounting principles		-		-		-		(6)
	$	356	$	216	$	3,252	$	(121)

               The following options to purchase PG&E Corporation common shares were outstanding, but not included in the computation of diluted EPS because the option exercise prices were greater than the average market price: six months ended June 2004 - 7,874,615, six months ended June 2003 - 19,769,750, three months ended June 30, 2004 - 8,235,055, three months ended June 30, 2003 - 19,777,800.

               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 account for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," 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. If compensation expense had been recognized using the fair value-based method under SFAS No. 123, PG&E Corporation's pro forma consolidated earnings (loss) and earnings (loss) per share would have been as follows:

			Three months ended				Six months ended
			June 30,				June 30,
(in millions, except per share amounts)			2004		2003		2004		2003
Net Earnings (Loss):
As reported			$	372	$	227	$	3,405	$	(127)
	Deduct: Total stock-based employee
		compensation expense determined
		under the fair value based method
		for all awards, net of related tax effects		4		5		9		10
Pro forma			$	368	$	222	$	3,396	$	(137)
Basic earnings (loss) per share:
As reported				0.89		0.56		8.22		(0.32)
Pro forma				0.88		0.55		8.20		(0.34)
Diluted earnings (loss) per share:
As reported				0.88		0.55		8.03		(0.31)
Pro forma				0.87		0.55		8.05		(0.34)

               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				Six months ended
			June 30,				June 30,
(in millions)			2004		2003		2004		2003
Net Earnings:
As reported			$	408	$	339	$	3,474	$	260
	Deduct: Total stock-based employee
		compensation expense determined
		under the fair value based method
		for all awards, net of related tax effects		2		2		4		4
Pro forma			$	406	$	337	$	3,470	$	256

               At June 30, 2004, a total of 2,086,860 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries, of which 1,278,820 shares were granted to Utility employees. At June 30, 2004, approximately 1,624,483 shares of restricted stock awarded to eligible employees of PG&E Corporation and its subsidiaries were outstanding, of which 1,075,266 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 Statement of Operations was approximately $3.2 million for the three-month period ended June 30, 2004 and $6.2 million for the six-month period ended June 30, 2004, of which approximately $1.9 million for the three-month period ended June 30, 2004 and $3.9 million for the six-month period ended June 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 June 30, 2004 was approximately $27 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, "Accounting for Derivative Instruments and Hedging Activities,'' as amended, or 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 June 30
Net income available for (loss allocated to)   common stock	$	372	$	227	$	408	$	339
Net gain (loss) in other comprehensive income (OCI)   from current period hedging transactions and price   changes in accordance with SFAS No. 133 (net of income tax   benefit of $3 million in 2003)	-		(4)		-		-
Net reclassification from OCI to earnings (net of income tax   expense of $7 million in 2003)	-		10		-		-
Retirement plan remeasurement (net of income tax   benefit of $41 million in 2003)		-		(60)		-		(60)
Comprehensive income	$	372	$	173	$	408	$	279
Six months ended June 30
Net income (loss) available for (loss allocated to)   common stock	$	3,405	$	(127)	$	3,474	$	260
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 $3 million in 2003)	3		(5)		3		-
Net reclassification from OCI to earnings (net of income tax   benefit of $4 million in 2003)	-		15		-		-
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		-		-		-
Comprehensive income (loss)	$	3,409	$	(174)	$	3,477	$	200

               The above changes to OCI are stated net of income tax expense (benefit) of $2 million for the six-month period ended June 30, 2004, and $(37) million for the three-month and $(46) million for the six-month periods ended June 30, 2003. There was no income tax expense (benefit) for the three-month period ended June 30, 2004.

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	15		-		-		-		15
Other	-		3		(60)		-		(57)
Balance at June 30, 2003	$	(80)	$	-	$	(60)	$	-	$	(140)
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
Net reclassification to earnings	-		-		-		-		-
Other	-		-		-		1		1
Balance at June 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 March 31, 2003	$	(86)	$	-	$	-	$	-	$	(86)
Period change in:
Mark-to-market adjustments for hedging      transactions in accordance with SFAS      No. 133	(4)		-		-		-		(4)
Net reclassification to earnings	10		-		-		-		10
Other	-		-		(60)		-		(60)
Balance at June 30, 2003	$	(80)	$	-	$	(60)	$	-	$	(140)
Balance at March 31, 2004	$	(78)	$	-	$	(4)	$	1	$	(81)
Period change in:
Mark-to-market adjustments for hedging      transactions in accordance with SFAS      No. 133	-		-		-		-		-
Net reclassification to earnings	-		-		-		-		-
Other	-		-		-		-		-
Balance at June 30, 2004	$	(78)	$	-	$	(4)	$	1	$	(81)

               Amounts included in accumulated other comprehensive income (loss) related to discontinued operations were $(77) million at June 30, 2004, and $(80) million at June 30, 2003.

Income Taxes

               In 2003, PG&E Corporation increased its valuation allowance against certain state deferred tax assets related to NEGT or its subsidiaries due to the uncertainty in their realization. Valuation allowances of $7 million for the three-month and $24 million for the six-month periods ending June 30, 2003, were recorded in discontinued operations, and $5 million in accumulated other comprehensive loss for the six-month period ended June 30, 2003.

               Upon deconsolidation of NEGT for financial statement purposes, PG&E Corporation adopted the cost method of accounting for its ownership interest in NEGT. As a result of this accounting change, PG&E Corporation has not recognized additional income tax benefits for financial statement reporting purposes after July 7, 2003, with respect to losses related to NEGT or its subsidiaries, even though it continues to include NEGT and its subsidiaries in its consolidated income tax returns. Any benefits and deferred tax assets arising from losses related to NEGT or its subsidiaries that have been recognized through July 7, 2003, will be recorded in discontinued operations in the Consolidated Statements of Operations at the time that PG&E Corporation releases its ownership interest in NEGT.

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 June 30,				Six Months Ended June 30,				Receivable (Payable) Balance Outstanding at
									June 30,		December 31,
(in millions)	2004		2003		2004		2003		2004		2003
Utility revenues from:
Administrative services provided to    PG&E Corporation	$	2	$	2	$	4	$	4	$	2	$	-
Natural gas transportation capacity services provided to NEGT ET	-		1		-		4		-		-
Trade deposit due from GTNW	-		-		-		-		-		15
Utility expenses from:
Administrative services received from    PG&E Corporation	$	20	$	85	$	42	$	98	$	(39)	$	(396)
Interest accrued on pre-petition liability due to    PG&E Corporation	-		2		2		4		-		(2)
Administrative services received    from NEGT	-		1		-		2		-		(1)
Gas commodity services    received from NEGT ET	-		-		-		10		-		-
Gas transportation services received  from GTNW	14		14		29		29		(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.

               Under SFAS No. 71, regulatory adjustments are recorded in the Consolidated Statements of Operations 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.

               Net periodic benefit cost as reflected in PG&E Corporation's and the Utility's Statement of Operations for the three and six-month periods ended June 30, 2004 and June 30, 2003 are as follows:

PG&E Corporation

	Pension Benefits Three Months Ended June 30				Other Benefits Three Months Ended June 30
(in millions)	2004		2003		2004		2003
Service cost for benefits earned	$	47	$	41	$	9		$	8
Interest cost	118		114		23			20
Expected return on Plan's assets	(142)		(122)		(19)			(15)
Amortization of transition obligation	2		3		6			7
Amortization of prior service cost	13		10		3			-
Amortization of recognized loss	-		10		-			1
Settlement loss	-		2		-			-
Net periodic benefit cost	$	38	$	58	$	22		$	21

	Pension Benefits Six Months Ended June 30				Other Benefits Six Months Ended June 30
(in millions)	2004		2003		2004		2003
Service cost for benefits earned	$	93	$	80	$	18		$	15
Interest cost	236		229		44			40
Expected return on Plan's assets	(282)		(243)		(38)			(29)
Amortization of transition obligation	3		7		13			13
Amortization of prior service cost	26		20		7			1
Amortization of recognized loss	-		20		-			2
Settlement loss	-		2		-			-
Net periodic benefit cost	$	76	$	115	$	44		$	42

Utility

	Pension Benefits Three Months Ended June 30				Other Benefits Three Months Ended June 30
(in millions)	2004		2003		2004		2003
Service cost for benefits earned	$	46	$	40	$	9		$	8
Interest cost	117		113		23			20
Expected return on Plan's assets	(141)		(121)		(19)			(15)
Amortization of transition obligation	2		3		6			7
Amortization of prior service cost	13		10		3			-
Amortization of recognized loss	-		10		-			1
Settlement loss	-		1		-			-
Net periodic benefit cost	$	37	$	56	$	22		$	21

		Pension Benefits Six Months Ended June 30						Other Benefits Six Months Ended June 30
(in millions)		2004			2003			2004			2003
Service cost for benefits earned		$	92		$	79		$	18		$	15
Interest cost		234			227			44			40
Expected return on Plan's assets		(281)			(242)			(38)			(29)
Amortization of transition obligation		3			7			13			13
Amortization of prior service cost		26			20			7			1
Amortization of recognized loss		-			20			-			2
Settlement loss	-			1			-			-
Net periodic benefit cost		$	74		$	112		$	44		$	42

               The Utility previously disclosed in its Annual Report for the year ended December 31, 2003 that it expected to contribute up to $129 million to its pension benefits plan, assuming favorable resolution of pension-related rate recovery in the 2003 general rate case, or GRC, in which it requested the CPUC to approve a related $75 million additional revenue requirement. The CPUC's May 27, 2004 decision in the Utility's 2003 GRC rejected the request for this $75 million additional revenue requirement. As a result, the Utility will not make the associated $129 million contribution for plan year 2003.

Accounting Pronouncements Issued But Not Yet Adopted

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

               In May 2004, 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-b, "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 related to the Prescription Drug Act. FSP 106-2 is effective for the third quarter of 2004, which begins on July 1, 2004. According to an actuarial assessment, the Utility's postretirement healthcare benefit plan does not qualify for the federal subsidy included in the Prescription Drug Act. However, FSP 106-2 is expected to have an impact on an employer's per-capita claim costs and future plan participation rates. PG&E Corporation and the Utility currently are evaluating t he impact on per-capita claim costs and future plan participation rates.

NOTE 2: THE UTILITY'S CHAPTER 11 FILING

               The discussion of the Utility's Chapter 11 filing matters below should be read in conjunction with Note 2 of the Notes to the Consolidated Financial Statements of PG&E Corporation's and the Utility's combined 2003 Annual Report filed with the Current Report on Form 8-K dated June 18, 2004.

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 bankruptcy. 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 will no longer be subject to the oversight of the bankruptcy court, the bankruptcy court will retain 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 cour t retains jurisdiction to resolve 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 resolution, reinstated certain obligations, and paid other obligations. The following table summarizes the sources and uses of funds for these transactions:

(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. On July 16, 2004, three California state senators filed a request for permission to file a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not acted yet on the petitions or the state senators' request. 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 and PG&E Corporation and the Utility's ability to make payments on debt could be materially adversely affected.

               The Utility believes that the uncertainty regarding the outcome of the pending appeals and petitions does not alter the assessment that the regulatory assets provided under the Settlement Agreement are probable of recovery in rates, as discussed below.

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), regulatory asset established under the Settlement Agreement, or the 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 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 the f irst quarter of 2004. As of June 30, 2004, the Utility has recorded after-tax offsets to the Settlement Regulatory Asset totaling approximately $180 million from supplier settlements.

· 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 be authorized to earn a rate of return as determined by the CPUC in the annual cost of capital proceeding. The Utility has requested a rate of return on its equity component of 11.22% in its cost of capital proceeding for 2004. (The Utility expects a final CPUC decision on this proceeding in December 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. On April 12, 2004, the Utility deposited $10 million into escrow accounts for the first installment payment to this corporation. As of June 30, 2004, the Utility has recorded an $83 million associated 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 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. During the first quarter of 2004, the Utility recorded a regulatory asset and associated liability of approximately $30 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 recor ded as a contribution 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 pre-tax 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 to be secured by 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 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 six months for the IRS to respond. Also, on July 22, 2004, the Utility filed an application with the CPUC requesting the authority to securitize the Settlement Regulatory Asset by issuing Energy Recovery Bonds as discussed above, in an aggregate principal amount of up to $3.0 billion in two separate tranches up to one year apart. The Utility requested that the CPUC act on this application by November 19, 2004. If the Utility receives a satisfactory and timely approval of this application, along with timely receipt of a favorable private letter ruling from the IRS, the issuance of the first series of Energy Recovery Bonds, in the amount of 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 o f return on the Settlement Regulatory Asset would be eliminated. Instead, the Utility would collect from customers amounts sufficient to service the principal and interest payments on the Energy Recovery Bonds. 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 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 June 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		(25.3)
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)
Remaining claims - principal, prior to the effectiveness of the Plan of Reorganization		10.8
Payments on claims upon the effectiveness of the Plan of Reorganization(2)		(8.2)
Reinstated Pollution Control Bonds				(0.8)
Amount retained in escrow for remaining disputed claims at June 30, 2004				$	1.8
Disputed claims not accrued by the Utility					(0.2)
Disputed claims accrued by the Utility at June 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 $340 million at June 30, 2004 and the Utility's provision for legal matters of approximately $193 million at June 30, 2004, as discussed below in Note 6.
(2)	The Utility also made payments of approximately $0.2 billion for interest and bank premiums.

              As of June 30, 2004, the Utility has accrued approximately $1.6 billion for remaining disputed claims, consisting of approximately $2.1 billion of accounts payable-disputed claims primarily payable to the ISO and PX, offset by an accounts receivable amount from the ISO and the PX of approximately $0.5 billion.  As discussed above, in connection with the implementation of the Plan of Reorganization, the Utility deposited $1.8 billion into escrow for the payment of disputed claims. Although the Utility was required to deposit $1.8 billion into escrow, the Utility does not believe it is probable that it will be found liable for approximately $0.2 billion of the $1.8 billion of the disputed claims and therefore, in accordance with SFAS No. 5, "Accounting for Contingencies," or SFAS No.5, the Utility 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
	June 30,		December 31,
(in millions)	2004		2003
PG&E Corporation
Senior secured notes, 6 ⅞%, due 2008	$	600	$	600
Convertible subordinated notes, 9.50%, due 2010		280		280
Other long-term debt	3		3
Total long-term debt	883		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
1.81% 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	8		-
Less current portion	(458)		(310)
Total long-term debt, net of current portion		7,845		2,431
Total consolidated long-term debt, net of current portion	$	8,728	$	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 and, together with 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 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 Mortgage Bonds is based on the six-month London Interbank Offered Rate, or LIBOR, plus 0.70%, that will reset quarterly beginning on July 3, 2004.

               In addition, approximately $2.5 billion of additional First Mortgage Bonds were used on the Effective Date to secure the Utility's credit facilities as described below and to support the Utility's reimbursement obligation under an insurance policy relating to certain pollution control bonds that were issued for the benefit of the Utility. On July 29, 2004, $345 million of First Mortgage Bonds were cancelled when the Utility repaid $345 million of the term loan credit facility.

               The First Mortgage Bonds are secured by a first priority lien 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 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, if either or both of these rating agencies do not then rate the Utility's long-term unsecured debt obligations, comparable ratings by any other nationally recognized rating agency or agencies selected by the Utility . The First Mortgage Bonds received initial investment grade credit ratings of Baa2 from Moody's and BBB from S&P.

               The First Mortgage Bonds have been issued under an indenture containing covenants that limit the Utility's ability to, among other things:

· Merge or consolidate with another entity; and

· Convey, lease or otherwise transfer all or substantially all of the Utility's assets.

               In addition, the indenture contains customary covenants, including covenants related to:

· Maintenance of the Utility's Diablo Canyon power plant, for as long as these facilities constitute mortgaged property;

· Maintenance of insurance for the mortgaged property;

· The timely payment of principal and interest; and

· Prompt recording, filing, re-recording, and re-filing of liens in the proper jurisdictions as required by law, until the release date.

               In addition, if the First Mortgage Bonds become unsecured obligations, 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 Bonds

               Obligations under pollution control loan agreements, under which the Utility is obligated to reimburse the California Pollution Control Financing Authority, or CPCFA, for funds received by the Utility from the issuance of the CPCFA's pollution control bonds for the benefit of the Utility, totaled $814 million at December 31, 2003. Interest rates on $614 million of $814 million of the obligations are variable. For the second quarter of 2004, the variable interest rates ranged from 1.02% to 1.05%. The interest rate on the remaining $200 million of the obligations is fixed at 5.35%. The CPCFA's obligation to pay principal and interest on the related pollution control bonds is backed by bond insurance and the Utility's obligation under the loan agreements are supported by the First Mortgage Bonds.

               The covenants under the variable rate and 5.35% pollution control bond loan agreements include customary covenants, including covenants related to:

· Maintenance of the Utility's corporate existence;

· Maintenance of the pollution control project assets;

· Limitation on assignment of the Utility's rights and obligations; and

· Limitation on mergers and sales of all or substantially all of the Utility's assets without CPCFA consent.

               On March 5, 2004, the Utility entered into four separate reimbursement agreements under which the issuing lender issued, on the Effective Date, approximately $620 million in new letters of credit to support the variable interest rate pollution control bonds in the approximate aggregate principal amount of $614 million plus interest payments of approximately $6 million. At June 30, 2004, there were no amounts drawn against the letters of credit. The covenants under the pollution control bond reimbursement agreements are substantially the same as those of the working capital facility, as described below. On the Effective Date, the Utility secured its obligation under the four separate reimbursement agreements with First Mortgage Bonds.

3.5% Pollution Control Bonds and Pollution Control Bonds Term Loans

               On March 5, 2004, the Utility entered into a term loan facility of $345 million that was used to fund the Utility's purchase, in lieu of redemption, of the Pollution Control Revenue Bonds, 1992 Series A and B and 1993 Series A and B, or collectively the Old Bonds, on the Effective Date.

               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 received by the Utility were used to repay the $345 million term loan facility. The CPCFA's obligation to pay principal and interest on the New Bonds is backed by bond insurance and the Utility's obligation under the new loan agreements are supported by the First Mortgage Bonds. The New Bonds must be purchased from their holders on June 1, 2007.

               The four loan agreements include customary covenants, including covenants related to:

· Maintenance of the Utility's corporate existence;

· Certain prohibitions, without the consent of the CPCFA, on the disposition of the project assets, other than dispositions of inventory and obsolete property in the ordinary course;

· Limitation on assignment of the Utility's rights and obligations; and

· Limitation on mergers and sales of all or substantially all of the Utility's assets without CPCFA consent.

Pollution Control Bond Bridge Facilities

               During the course of 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, were redeemed through draws on letters of credit, giving rise to an obligation to reimburse the issuers of these letters of credit or their respective assignees for the amounts drawn. These agreements serve as taxable bridge loans to facilitate the Utility's refinancing with long-term tax-exempt pollution control bonds or taxable debt. On the Effective Date, the Utility amended the four separate reimbursement agreements and restated them after the lenders had purchased the $454 million in reimbursement obligations owed to the issuers of the drawn letters of credit or their respective assignees. The outstanding balance of $454 million at June 30, 2004 under the amended and restated reimbursement agreements is due and payable o n 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.

               The covenants under each amended and restated reimbursement agreement are substantially identical to those of the working capital facility, as described below. On the Effective Date, the Utility secured its obligations under the amended and restated reimbursement agreements with the First Mortgage Bonds.

Repayment Schedule

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

(in millions)	2004		2005		2006		2007		2008		Thereafter		Total
Long-term debt:
Fixed rate obligations	$	1	$	-	$	-	$	345	$	-	$	5,282	$	5,628
Average interest rate	7.40%		-%		-%		-%		-%		5.34%		5.22%
Variable rate obligations	-		454		1,600		614		-		-		2,668
Other	3		2		1		-		-		1		7
Total	$	4	$	456	$	1,601	$	959	$	-	$	5,283	$	8,303

Credit Facilitiesand Short-Term Borrowings

               The following table summarizes the Utility's lines of credit and short-term borrowings subject to compromise outstanding at December 31, 2003, which were paid and cancelled on the Effective Date. At June 30, 2004, the Utility and its consolidated subsidiaries had not utilized any of its credit facilities. PG&E Corporation does not maintain credit facilities or short-term borrowings.

               The Utility's and its consolidated subsidiaries' credit facilities and agreements consist of the following:

(in millions)
			June 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				-
Letters of Credit
	Pollution Control Bonds Reimbursement    Agreements		-					620
	Working capital facility		-					191
		Total Letters of Credit	$		-		$	811
Credit facilities subject to compromise
	5-year revolving credit facility									938
		Total lines of credit subject to compromise							$		938
Short-term borrowings subject to compromise
	Bank borrowings - 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

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 will sell 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 rate 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 under 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, the Utility paid off this credit facility, and on June 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 receivables) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivables 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. When amounts are drawn on the facility, the pledged receivables and the corresponding debt are included as Accounts Receivable and Long-term Debt on the consolidated balance sheet.

               The accounts receivable facility includes customary covenants on the Utility's part and on the part of PG&E ARC, including covenants related to:

· Servicing of the accounts receivables in accordance with the Utility's credit and collection policy;

· Protecting the interests of the purchasers of the accounts receivable;

· Maintenance of any governmental authorization or approval necessary in connection with the operation of the Utility's business; and

· Indemnification of the purchasers.

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 June 30, 200 4. However, the Utility had approximately $191 million of letters of credit outstanding. In July 2004, two natural gas procurement and transportation service providers extended credit to the Utility, thereby reducing the letters of credit, which were outstanding at June 30, 2004, by approximately $13 million.

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

· Maintenance, as of the end of each fiscal quarter ending after the Effective Date, of a debt to capitalization ratio of at most 0.65 to 1.00;

· Prohibition on the disposition of assets, other than dispositions of inventory and obsolete property in the ordinary course of business, in excess of 25% of the aggregate book value of the Utility's and the Utility's significant subsidiaries' assets at December 31, 2003;

· A limitation on liens no more restrictive than the limitation on liens that becomes effective under the First Mortgage Bonds indenture from and after the release date;

· Limitation on mergers and sales of all or substantially all of the Utility's assets; and

· Maintenance of any governmental authorization or approval necessary in connection with the operation of the Utility's business.

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. 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 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 marked to market on PG&E Corporation's Consolidated Statements of Operations 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). From the issuance date of the Convertible Notes on June 25, 2002, through December 31, 2003, the fair value of the dividend participation rights component was considered immaterial. At June 30, 2004, the estimated fair value of the dividend participation rights component was $65.2 million, an increase in value of $19.6 million, net of taxes, from March 31, 2004.

NOTE 4: DISCONTINUED OPERATIONS

               On July 8, 2003, NEGT filed a voluntary petition for relief under Chapter 11. The combination of the decline in wholesale electricity prices, the financial commitments related to NEGT's construction program, the decline of NEGT's credit rating to below investment grade, and the lack of market liquidity created severe financial distress and ultimately caused NEGT to seek protection under Chapter 11. As a result of NEGT's Chapter 11 filing and the elimination of equity ownership provided for in NEGT's plan of reorganization, PG&E Corporation considers its investment in NEGT to be an abandoned asset and has accounted for NEGT as discontinued operations in accordance with SFAS No. 144. Under the provisions of SFAS No. 144, the operating results of NEGT and its subsidiaries are reported as discontinued operations in the Consolidated Statements of Operations through July 7, 2003 and for all prior periods.

               Effective July 8, 2003, NEGT and its subsidiaries are no longer consolidated by PG&E Corporation in its Consolidated Financial Statements. The accompanying June 30, 2004 Consolidated Balance Sheet of PG&E Corporation does not reflect the separate assets and liabilities of NEGT; rather, a liability of approximately $1.2 billion is reflected, which represents the losses of NEGT recognized by PG&E Corporation in excess of its investment in and advances to NEGT. In addition, accumulated other comprehensive income includes a net charge of approximately $77 million at June 30, 2004 related to NEGT. The accompanying Consolidated Statements of Operations of PG&E Corporation for the six months ended June 30, 2003 present the operations of NEGT as discontinued operations. PG&E Corporation's investment in NEGT will not be affected by changes in NEGT's future financial results, other than (1) investments in or dividends from NEGT, or (2) income taxes PG&E Corporation may be required to pay if the IRS disallows certain deductions or tax credits related to NEGT or its subsidiaries for past tax years that are incorporated into PG&E Corporation's consolidated tax returns.

               On May 3, 2004, NEGT's plan of reorganization was confirmed by the bankruptcy court. The plan of reorganization is expected to become effective during the second half of 2004. The effective date is contingent upon certain conditions being met within 90 days following the plan confirmation. Upon implementation of NEGT's plan of reorganization, PG&E Corporation will reverse its investment in NEGT and the related amounts included in deferred income taxes and in accumulated other comprehensive income and, as a result, will recognize a material one-time net non-cash gain to earnings from discontinued operations. This amount will be reduced by any potential liability for NEGT claims related to contractual or contingent obligations not resolved by the plan of reorganization, if any. The deferred tax assets arising from the losses related to NEGT or its subsidiaries that have been recognized through July 7, 2003, wi ll reverse at the time PG&E Corporation's ownership interest in NEGT is cancelled, and will partially offset the one-time gain.

NEGT Operating Results

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

		Six months ended
(in millions)		June 30, 2003
Operating revenues(1)		$	562
Loss before income taxes(1)		(592)
Net income(1)		(372)
(1)	Amounts shown have been adjusted for intercompany eliminations.

               Before PG&E Corporation began accounting for NEGT as discontinued operations, 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 June 30, 2003 and the other previously discontinued operations through the respective disposal dates. The pre-tax loss of NEGT and its subsidiaries for the six months ended June 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. Also included in the first quarter 2003 pre-tax loss are impairments, write-offs, and other charges of approximately $199 million.

Commitments and Contingencies of NEGT

               With its Chapter 11 filings, NEGT affiliates defaulted on numerous agreements. The amounts due as a result of these defaults will be determined and resolved in the context of NEGT Chapter 11 filings. PG&E Corporation is not a party to these agreements, nor does it anticipate any obligation related to these agreements.

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 June 30, 2004, cash flow hedges associated with natural gas commodity price risk are presented at fair value of $3 million in other current liabilities on the Utility's Consolidated Balance Sheets. At June 30, 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 and are subject to the provisions of SFAS No. 71, therefore, the effective and ineffective portions are recorded on the balance sheet in regulatory accounts.

               The Utility has certain non-trading 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 normal purchases and sales exception or are not derivative instruments and, therefore, have no mark-to-market effect on earnings. Additionally, the Utility holds an immaterial amount of other non-trading derivative instruments that do not qualify for cash flow hedge accounting or the normal purchase and sales exception to SFAS No. 133. The fair value of $10 million at June 30, 2004 for these derivative instruments is recorded in other current assets or liabilities offset by regulatory liabilities or assets.

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 $2.1 billion at June 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 $58 million at June 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.

               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 or obtain 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 six months of 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At June 30, 2004, there were threecounterparties that represented greater than 10% of the Utility's net wholesale credit exposure. These three investment grade counterparties represented a total of approximately 64% 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 June 30, 2004 and December 31, 2003.

(in millions)		Gross Credit Exposure BeforeCredit Collateral(1)		Credit Collateral		Net Credit Exposure(2)		Number of Wholesale Customers or Counterparties >10%	Net Exposure to Wholesale Customers or Counterparties >10%
June 30, 2004		$	134		14		120	3		77
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 June 30, 2004 and December 31, 2003:

(in millions)		Net Credit Exposure(2)		Percentage of Net Credit Exposure
Credit Quality(1)
June 30, 2004
Investment grade(3)		$	116	97%
Non-investment grade		4		3%
Total		$	120	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. PG&E Corporation's and the Utility's commitments are discussed more fully in their combined 2003 Annual Report on Form 10-K. The following summarizes PG&E Corporation's and the Utility's material contingencies and canceled, new, and significantly modified commitments since the combined 2003 Annual Report on Form 10-K was filed.

Commitments

Utility

Power Purchase Agreements

               During the six-month period ended June 30, 2004, the Utility entered into various agreements to purchase energy. Under these agreements, the Utility is committed to make energy payments of approximately $277 million and capacity payments of approximately $28 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 June 30, 2004, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

(in millions)
2004	$	499
2005	301
2006	26
2007	7
2008	-
Thereafter	-
Total	$	833

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

(in millions)
2004	$	118
2005	28
2006	29
2007	38
2008	30
Thereafter	64
Total	$	307

Transmission Control Agreement

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

               At June 30, 2004, the ISO had RMR agreements for which the Utility could be obligated to pay the ISO an estimated $623 million in net costs during the period July 1, 2004, to June 30, 2006. These costs are recoverable under 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 approving rates that, if affirmed by the FERC, would require the subsidiaries of Mirant Corporation, or Mirant, that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $340 million, including interest, for availability of Mirant's RMR Plants under these agreements. However, 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 on this issue, what the FERC's decision will be, and the amount of any refunds, which may be impacted by Mirant's Chapter 11 filing. It is uncertain how the resolution of this matter would be reflected in the Utility's rates.

Contingencies

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

2003 General Rate Case

               On May 27, 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 approves 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
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
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, the Utility has recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets and unfunded taxes, depreciation, and decommissioning. The net impact of these items on a pre-tax basis for the three and six-month periods ended June 30, 2004 is as follows:

(in millions)	2003		2004		Previously Recorded		Net 2004 Adjustment
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 subject to refund 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 began recording 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 has 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 has recorded both the 2003 and 2004 natural gas distribution revenue requirement increase 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 has 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 April 2004, a CPUC ALJ issued a proposed decision, which would approve certain storm response improvement initiatives as well as the funding for these initiatives. In early July 2004, a revised proposed decision was issued that would modify the CPUC's existing reliability standard to require the Utility to meet improved reliability targets, but did not specify any particular penalties if the Utility failed to meet those targets. On June 24, 2004, an alternate proposed decision was issued that would adopt a reliability performance incentive mechanism for the years 2005 through 2007 but with more stringent reliability performance targets than proposed by the Utility. Under the proposed performance incentive mechanism the Utility could receive up to $42 million each year depending on the extent to which the Utility exceeded the reliability performance improve ment targets, but could be required to pay a penalty of up to $42 million a year depending on the extent to which it failed to meet the targets. Neither the revised proposed decision nor the alternate proposed decision would provide the Utility with additional revenues to meet the more stringent reliability standards. If either the revised proposed decision or the alternate proposed decision is issued, there is an increased risk that the Utility would incur a penalty if it failed to meet the new performance reliability targets. The CPUC is expected to issue a final decision in the third quarter of 2004.

PX Block-Forward Contracts

               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 plaintiff's 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 its Diablo Canyon power plant, or 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 $40.2 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 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 Nuclear Regulatory Commission, or 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. The Utility must deposit collateral with the California Department of Industrial Relations, or DIR, to maintain its status as a self-insurer for workers' compensation claims made against the Utility. Acceptable forms of collateral include surety bonds, letters of credit, cash and securities. At June 30, 2004, the Utility provided collateral in the form of $305 million in surety bonds and approximately $43 million in a cash deposit.

               In February 2001, several surety companies provided cancellation notices because of the Utility's financial situation. The cancellation of these bonds has not impacted the Utility's self-insured status under California law. The DIR has not agreed to release the canceling sureties from their obligations for claims occurring before the cancellation and has continued to apply the canceled bond amounts, totaling $185 million, toward the $348 million collateral requirement. At June 30, 2004, the Utility's $348 million in collateral consisted of the $185 million in cancelled bonds, $120 million in active surety bonds and approximately $43 million in cash. PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with these surety bonds and the Utility's underlying obligation to pay workers' compensation claims.

               The DIR has determined that the Utility is eligible to participate in the Alternative Security Program, or ASP, administered by California's Self-Insurers' Security Fund, or SISF. The Utility was ineligible to participate in the ASP while in Chapter 11. 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 that existed at June 30, 2004. As a result, PG&E Corporation's guarantee of the Utility's reimbursement obligation associated wi th the surety bonds in place as collateral 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.

California Energy Crisis Proceedings

FERC Proceeding

               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. In December 2002, a FERC ALJ issued an initial decision finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001 (the only time period for which the FERC permitted refund claims), but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

               In an October 2003 decision, the FERC confirmed most of the ALJ's findings, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the Power Exchange, or 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 December 2004. The PX cannot make its compliance filing until after the ISO makes its filing. The actual refunds will not be determined until the FERC issues a final decision, following the ISO and PX compliance filings. The FERC is uncertain when it will issue a final decision in this proceeding, after which appellate review is expected. In addition, future refunds could increase or decrease as a result of retroactive adjustment proposed by the ISO, which incorporate revised data provided by the Utility and other entities. The FERC has indicated that it does not have the power to direct refunds for the period before October 2, 2000, but has engaged in an investigation of market manipulation and sought through settlement or hearings disgorgement of profits for any tariff violations during this period. Unless settled among the various entities, this conclusion will also be subject to judicial review. On July 27, 2004, the U.S. Court of Appeals for the Ninth Circuit issued an order allowing a lawsuit brought by the CPUC and SCE challenging the FERC's refund period for California power purchases to proceed.

               The Utility and other California agencies have entered into settlement agreements with some sellers, and have initiated settlement discussions with many market participants to attempt to resolve amounts due to California and the Utility. Settlement discussions with a number of major sellers are continuing. A settlement conference was held June 30, 2004, at the FERC, which laid out the framework for how the settlements may proceed. Subsequently, individual meetings with a number of market participants have occurred. The Utility cannot predict whether these settlement negotiations will be successful or whether further litigation may occur in connection with claimed refunds and recovery of excessive charges.

               Under the Settlement Agreement, the Utility and PG&E Corporation agreed to continue to cooperate with the CPUC and the state of California in seeking refunds from generators and other energy suppliers. The net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relating to the Utility's ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offset will reduce the balance of the Settlement Regulatory Asset.

               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 October 2003 decision could further reduce the amount of the suppliers' claims by several hundred million dollars. However, this reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology. 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 related to this FERC proceeding described below. The net after-tax amounts received by the Utility under these settlements will result in a reduction to the Utility's Settlement Regulatory Asset.

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. 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. 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.

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 gas customers would receive approximately $80 million and its electricity customers would receive approximately $215 million 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 time El Paso made upfront payments totalin g approximately $568 million to all parties to the settlement agreement. The Utility's share of El Paso's $568 million payments 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 will refund the natural gas payment received from El Paso to core procurement customers in the third quarter of 2004. 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, or approximately $42 million, as an offset to the outstanding balance of the Settlement Regulatory Asset in June 2004.

Williams Settlement

               On February 24, 2004, the Utility and SCE entered into a settlement agreement with The Williams Companies, or the Williams, settling certain pre-petition claims in the Utility's Chapter 11 proceeding. The FERC approved the settlement on July 2, 2004. Under the Williams settlement, the Utility will receive an after-tax credit of approximately $40 millionthat will reduce the Settlement Regulatory Asset and other regulatory balancing accounts. The Utility must seek approval from the bankruptcy court to realize the after-tax credit associated with this settlement.

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. In order for the Dynegy settlement to become effective, it must be approved by the CPUC and the FERC. If the Dynegy 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 above under "FERC Proceeding." A definitive agreement to implement the Dynegy sett lement was filed with the FERC on June 28, 2004 and is pending approval. The Utility expects that the Dynegy Settlement will be approved in the third quarter of 2004.

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 CPUC and the FERC. The Utility plans to file a definitive agreement to implement the settlement with the FERC by August 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 Proceeding" above.

               The CPUC decision approving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the amounts actually received by the Utility under pending settlements with energy suppliers, including the settlements discussed above.

DWR Contracts

               The California Department of Water Resources, or DWR, provided approximately 24% of the electricity delivered to the Utility's customers for the six-month period ended June 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

               NEGT and its creditors have filed a complaint against PG&E Corporation and two PG&E Corporation officers who previously served on NEGT's Board of Directors, in its Chapter 11 proceeding asserting, among other claims, that NEGT is entitled to be compensated under an alleged implied tax sharing agreement between PG&E Corporation and NEGT for any tax savings achieved by PG&E Corporation as a result of the incorporation of the losses and deductions related to NEGT or its subsidiaries in PG&E Corporation's consolidated federal income tax return. In May 2003, PG&E Corporation received a return of $533 million from the IRS for an overpayment of 2002 estimated federal income taxes. In November 2003, NEGT and its creditors amended their complaint to add additional causes of action arising out of or related to the filing by PG&E Corporation of its 2002 federal consolidated tax return and certain r estructuring negotiations that occurred between PG&E Corporation and certain of NEGT's creditors prior to NEGT's Chapter 11 proceeding, including claims for breach of contract, breach of fiduciary duty, violation of the automatic stay, turnover, an accounting, unjust enrichment, fraudulent transfer, constructive trust, breach of standstill agreement, deceit, equitable subordination and indemnification. NEGT and the creditors' committees seek a declaration that an implied tax sharing agreement exists between PG&E Corporation and NEGT as well as injunctive relief prohibiting PG&E Corporation from taking certain tax positions on its consolidated tax returns in the future. The complaint also alleges a cause of action for breach of fiduciary duty against two PG&E Corporation officers who previously served on NEGT's Board of Directors.

               NEGT and its creditors have asserted that they have a direct interest in certain tax savings achieved by PG&E Corporation and are entitled to be paid approximately $414 million of the funds received by PG&E Corporation (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 seek punitive damages against PG&E Corporation and the former NEGT directors for breach of fiduciary duty and seek punitive damages against PG&E Corporation for deceit as well as interest, costs of suit, and reasonable attorney fees.

               On April 6, 2004, in response to defendants' motion to dismiss many of the plaintiffs' claims, the bankruptcy court entered a memorandum decision dismissing the following claims: (1) violation of the automatic stay, (2) turnover of property, (3) an accounting, (4) injunctive relief, (5) constructive trust, (6) equitable subordination, and (7) indemnification. The bankruptcy court denied the motion to the extent that it sought dismissal of plaintiffs' claims for breach of fiduciary duty, declaratory judgment, unjust enrichment, fraudulent conveyance, breach of standstill agreement, and deceit. Accepting plaintiffs' allegations as true, as the court is required to do on a motion to dismiss, the bankruptcy court concluded that plaintiffs stated a claim or that factual issues existed with respect to these claims that precluded dismissal at this stage of the proceeding.

               Defendants filed a motion in the U.S. District Court of Maryland seeking to transfer the litigation from the bankruptcy court to the District Court. On April 22, 2004, the District Court approved the motion to transfer, and set a trial date for March 2005.

               PG&E Corporation denies that any tax sharing agreement, whether implied or expressed, ever existed and denies that it has any obligation to compensate NEGT for the incorporation of losses, deductions or tax credits related to NEGT or its subsidiaries into PG&E Corporation's consolidated federal tax returns, as required under the Internal Revenue Code. Until the dispute is resolved, PG&E Corporation is treating $361.5 million as restricted cash. PG&E Corporation anticipates continuing to incorporate income or losses, deductions and certain tax credits related to NEGT or its subsidiaries in PG&E Corporation's consolidated income tax return until NEGT is no longer consolidated for federal income tax purposes. NEGT and its creditors have asserted that NEGT should be compensated for any resulting tax savings.

               PG&E Corporation does not expect that the outcome of this matter will have a material adverse effect on its results of operations, financial position or liquidity.

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 $340 million at June 30, 2004 and approximately $314 million at December 31, 2003. During the first half of 2004, the liability increased by approximately $26 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $340 million accrued at June 30, 2004 includes approximately $103 million related to the pre-closing remediation liability associated with divested generation facilities and approximately $237 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 former manufactured gas plant si tes. Of the approximately $340 million environmental remediation liability, approximately $145 million has been included in prior rate setting proceedings and the Utility expects that approximately $148 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 $455 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 $455 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. The Utility's Plan of Reorganization provides that the Utility will respond to these types of claims in the ordinary course of business and since the Utility has not argued that the Chapter 11 proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the California Attorney General's claims seeking specific cash recoveries are unenforceable. 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 for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at June 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 $193 million (which includes the $160 million reserve discussed above) at June 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 June 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. PG&E Corporation also owns 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 U.S.

The Utility

               The Utility served approximately 4.9 million electricity distribution customers and approximately 4.0 million natural gas distribution customers at June 30, 2004. The Utility had approximately $33.8 billion in assets at June 30, 2004 and generated revenues of approximately $5.5 billion in the six months ended June 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.

               The discussion of the Utility's Chapter 11 proceedings below should be read in conjunction with Note 2 of the Notes to the Consolidated Financial Statements of PG&E Corporation's and the Utility's combined 2003 Annual Report filed with the Current Report on Form 8-K dated June 18, 2004.

Emergence From Chapter 11

               On April 12, 2004, the Utility's plan of reorganization, or Plan of Reorganization, under Chapter 11 of the U.S. Bankruptcy Code became effective, at which time the Utility emerged from bankruptcy. 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 resolve remaining disputed claims.

               In light of the satisfaction of various conditions to the implementation of the Plan of Reorganization, including the consummation of the public offering of $6.7 billion in first mortgage bonds, or 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 Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," as amended, or 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 approximately $4.9 billion of regulatory assets established under the Settlement Agreement and a related after-tax gain on recognition of these regulatory assets of approximately $2.9 billion in the first quarter of 2004.

               In anticipation of its emergence from Chapter 11, the Utility consummated its public offering of $6.7 billion in 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 resolution, reinstated certain obligations, and paid other obligations. The following table summarizes the sources and uses of funds for these transactions:

(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 District Court, dismissed 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. On July 16, 2004, three California state senators filed a request for permission to file a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not acted yet on the petitions or the state senators' request. PG&E Corporation and the Utility belie ve 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 and PG&E Corporation and the Utility's ability to make payments on debt could be materially adversely affected.

               The Utility believes that the uncertainty regarding the outcome of the pending appeals and petitions does not alter the assessment that the regulatory assets provided under the Settlement Agreement are probable of recovery in rates as discussed below.

Approval of 2003 General Rate Case

               On May 27, 2004, the CPUC issued a decision in the Utility's 2003 General Rate Case, or 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 in the Regulatory Matters section.

               As a result of the GRC decision, the Utility has recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of unfunded taxes, depreciation, and decommissioning. The net impact of these items on a pre-tax basis was approximately $432 million for the three and six-month periods ended June 30, 2004.

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 is provided in a cost-effective and environmentally sound manner. 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 serv ice providers, collectively referred to as LSEs), 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 MD&A, contains forward-looking statements 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;

· The extent to which 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 California Department of Water Resources, or DWR, electricity contracts allocated to the Utility's customers) increases or decreases due to changes in customer and economic growth rates, the periodic expiration or termination of the Utility's or the DWR's power purchase contracts, the reallocation of the DWR power purchase contracts among the California investor-owned electric utilities, whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR, the retirement or other closure of the Utility's electricity generation facilities, the performance of the Utility's electricity generation facilities, the extent to which the Utility purchases or builds electricity generation faci lities, and other factors;

· 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 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 $2.21 billion after-tax regulatory asset established under the Settlement Agreement are met, and if so, the timing and amount of the securitization;

· 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 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;

· 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 service by local public utilities, self-generation by the Utility's customers and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load, and additional barriers to cost recovery; 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 and the extent to which cities, counties and others in the Utility's service territory begin directly serving the Utility's customers, without fair compensation.

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 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 a $2.2 billion, after-tax ($3.7 billion, pre-tax), regulatory asset established under the Settlement Agreement, or Settlement Regulatory Asset, and a $0.7 billion, after-tax ($1.2 billion, pre-tax), regulatory asset 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 settlement, after-tax	(8)		-		(8)
Net regulatory assets, after-tax, March 31, 2004	$	2,168	$	728	$	2,896

               SettlementRegulatory 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. The Settlement Regulatory Asset will be fully amortized by the end of 2012. This after-tax 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, including those a rising 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 the first quarter of 2004. As of June 30, 2004, the Utility has recorded after-tax offsets to the Settlement Regulatory Asset totaling approximately $180 million from supplier settlements.

               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 approximately $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 be authorized to earn a rate of return as determined by the CPUC in the annual cost of capital proceeding. (The Utility has requested a rate of return on its equity com ponent of 11.22% in its cost of capital proceeding for 2004. The Utility expects a final CPUC decision on this proceeding in December 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. On April 12, 2004, the Utility deposited $10 million into escrow accounts for the first installment payment to this corporation. As of June 30, 2004, the Utility has recorded an $83 million associated 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 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 requires 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. During the first quarter of 2004, the Utility recorded a regulatory asset and associated liability of approximately $30 million for 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 tran sactions were recorded as a contribution 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 of 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 pre-tax 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, 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 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 six months for the IRS to respond. Also on July 22, 2004, the Utility filed an application with the CPUC requesting authority to securitize the Settlement Regulatory Asset by issuing Energy Recovery Bonds as discussed above, in an aggregate principal amount of up to $3.0 billion in two separate tranches up to one year apart. The Utility requested that the CPUC act on this application by November 19, 2004. If the Utility receives a satisfactory and timely approval of this application along with timely receipt of a favorable private letter ruling from the IRS, the issuance of the first series of Energy Recovery Bonds, in the amount of 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 retu rn on the Settlement Regulatory Asset would be eliminated. Instead, the Utility would collect from customers amounts sufficient to service the principal and interest payments on the Energy Recovery Bonds. 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.

NEGT

NEGT's Chapter 11 Filing

               On July 8, 2003, NEGT filed a voluntary petition for relief under Chapter 11. The combination of the decline in wholesale electricity prices, the financial commitments related to NEGT's construction program, the decline of NEGT's credit rating to below investment grade and the lack of market liquidity created severe financial distress and ultimately caused NEGT to seek protection under Chapter 11. In anticipation of NEGT's Chapter 11 filing, PG&E Corporation's representatives, who previously served as directors of NEGT, resigned on July 7, 2003 and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over NEGT. On May 3, 2004, NEGT's plan of reorganization, which eliminates PG&E Corporation's equity ownership, was confirmed by the bankruptcy court.

               As a result of NEGT's Chapter 11 filing and the elimination of equity ownership provided for in NEGT's proposed plan of reorganization, PG&E Corporation considers its investment in NEGT to be an abandoned asset and has accounted for NEGT as discontinued operations in accordance with SFAS No. 144, "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 accounts for NEGT using the cost method and NEGT is no longer consolidated by PG&E Corporation for financial reporting purposes. The accompanying June 30, 2004 Consolidated Balance Sheet of PG&E Corporation does not reflect the separate assets and liabilities of NEGT; ra ther, a liability of approximately $1.2 billion is reflected, which represents the losses recognized by PG&E Corporation in excess of its investment in and advances to NEGT. PG&E Corporation's investment in NEGT will not be affected by changes in NEGT's future financial results.

               When NEGT's plan of reorganization is implemented, which is anticipated to occur during the second half of 2004, PG&E Corporation will reverse its investment in NEGT and related amounts included in deferred income taxes and accumulated other comprehensive income and, as a result, recognize a material one-time net non-cash gain to earnings from discontinued operations. The effective date is contingent upon certain conditions being met within 90 days following the plan confirmation.

               NEGT and its creditors have filed a complaint against PG&E Corporation and two PG&E Corporation officers who previously served on NEGT's Board of Directors asserting, among other claims, that NEGT is entitled to be compensated under an alleged implied tax sharing agreement between PG&E Corporation and NEGT for any tax savings achieved by PG&E Corporation as a result of the incorporation of losses and deductions related to NEGT or its subsidiaries in PG&E Corporation's consolidated federal income tax return. In May 2003, PG&E Corporation received $533 million from the IRS for an overpayment of 2002 estimated federal income taxes. NEGT and its creditors have asserted that they have a direct interest in certain tax savings achieved by PG&E Corporationand are entitled to be paid approximately $414 million of the funds received by PG&E Corporation (approximately $361.5 million ach ieved 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). Consequently, until the dispute is resolved, PG&E Corporation is treating $361.5 million as restricted cash. PG&E Corporation anticipates continuing to incorporate losses, deductions and certain tax credits related to NEGT or its subsidiaries in PG&E Corporation's consolidated federal tax return until NEGT is no longer consolidated for federal income tax purposes. NEGT and its creditors similarly assert that NEGT is entitled to be compensated for any tax savings resulting from inclusion of these losses in PG&E Corporation's federal tax return. PG&E Corporation denies that any tax sharing agreement, whether implied or expressed, ever existed and denies that it has any obligation to compensate NEGT for the incorporation of losses and deductions related to NEGT or its subsidiaries into PG&E Corporation's consolidated federal tax returns.

               PG&E Corporation does not expect that the outcome of this matter will have a material adverse effect on its results of operations, financial position or liquidity.

RESULTS OF OPERATIONS

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

		Three Months Ended June 30,					Six Months Ended June 30,
(in millions)		2004			2003			2004			2003
Utility
Electric operating revenues		$	2,063		$	2,058	$	3,851	$		3,412
Natural gas operating revenues			686		657			1,617		1,487
Cost of electricity			685		562			1,254		1,162
Cost of natural gas			278		320			857		806
Operating and maintenance			748		714			1,557		1,441
Recognition of regulatory assets			-		-			(4,900)		-
Depreciation, amortization and decommissioning			352		307			650		605
Reorganization professional fees and expenses			4		65			6		100
Operating income			682		747			6,044		785
Interest income			23		20			34		31
Interest expense			(158)		(224)			(372)		(444)
Other income, net(1)			20		5			26		14
Income before income taxes			567		548			5,732		386
Income tax provision			159		209			2,258		125
Income before cumulative effect of a change   in accounting principle			408		339			3,474		261
Cumulative effect of a change in accounting principle			-		-			-		(1)
Income available for common stock		$	408	$	339		$	3,474		$	260
PG&E Corporation, Eliminations and Other(2)(3)
Operating revenues		$	-	$	(1)		$	-		$	(3)
Operating expenses			10		(26)			20		(52)
Operating income			(10)		25			(20)		49
Interest income			2		2			5		3
Interest expense			(18)		(36)			(34)		(71)
Other income (expense), net(1)			(34)		1			(67)		-
Loss before income taxes			(60)		(8)			(116)		(19)
Income tax provision (benefit)			(24)		3			(47)		(3)
Loss from continuing operations			(36)		(11)			(69)		(16)
Discontinued operations			-		(101)			-			(366)
Cumulative effect of changes in accounting principles			-		-			-			(5)
Net loss		$	(36)	$	(112)		$	(69)		$	(387)
Consolidated Total(3)
Operating revenues		$	2,749	$	2,714		$	5,468		$	4,896
Operating expenses (gain)			2,077		1,942			(556)		4,062
Operating income			672		772			6,024		834
Interest income			25		22			39		34
Interest expense			(176)		(260)			(406)		(515)
Other income (expenses), net(1)			(14)		6			(41)		14
Income before income taxes			507		540			5,616		367
Income tax provision			135		212			2,211		122
Income from continuing operations			372		328			3,405		245
Discontinued operations			-		(101)			-			(366)
Cumulative effect of changes in accounting principles			-		-			-			(6)
Net income (loss)		$	372	$	227		$	3,405		$	(127)
(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

Significant Factors Affecting Results

               With the implementation of new CPUC-approved electricity balancing accounts in 2004, electricity procurement costs and items such as changes in sales volumes no longer have the same impact on the Utility's results of operations that they had in prior years. As a result of CPUC decisions approving the Settlement Agreement and implementing various ratemaking mechanisms, the Utility no longer collects the frozen electric rates and surcharges that it collected in 2003, 2002, and 2001. Instead, the Utility collects cost-of-service based electric rates that are the sum of individual revenue requirement components, including base revenue requirements, revenue requirements for the Settlement Regulatory Asset, electricity procurement costs, and the DWR revenue requirement, among others. The GRC determines the amount of authorized base revenues the Utility can collect from customers to recover its basic business and operati onal costs for electricity and natural gas distribution operations and for electricity generation operations.

               During the California energy crisis, electricity procurement costs impacted the Utility's results of operations and financial condition. 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, for 2004 and beyond, electricity procurement costs are not expected to have the same impact on the Utility's results of operations that they had during the California energy crisis. However, the level of electricity procurement costs will continue to have an impact on cash flows.

               Operating expenses are a key factor in determining whether the Utility earns its authorized rate of return. The ratemaking mechanisms discussed above are intended to provide the Utility the opportunity to fully recover its costs. If the Utility does not recover its actual operating and maintenance expenses through rates because they exceed the level forecasted in the 2003 GRC or other ratemaking proceeding or because they are otherwise disallowed, the Utility may be unable to earn its authorized rate of return.

               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 $1.7 billion annually over the next five years, excluding costs associated with potential new generation development or implementation of advanced metering systems. A significant outage at any of the Utility's operating facilities may have a material impact on the Utility's operations. Costs associated with replacement electricity and natural gas or use of alternative facilities during these outages could have an adverse impact on PG&E Corporation's and the Utility's results of operations and liquidity.

               The following presents the Utility's operating results for the three and six-month periods ended June 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				Six months ended
	June 30,				June 30,
(in millions)	2004		2003		2004		2003
Residential	$	782	$	823	$	1,757	$	1,743
Commercial	946		1,036		1,812		1,847
Industrial	289		317		556		576
Agricultural	123		130		184		198
DWR pass-through revenue	(449)		(569)		(919)		(1,323)
Subtotal	1,691		1,737		3,390		3,041
Miscellaneous	372		321		461		371
Total electric operating revenues	$	2,063	$	2,058	$	3,851	$	3,412

               For the three months ended June 30, 2004, the Utility's electric operating revenues increased approximately $5 million compared to the same period in 2003 mainly due to the following factors:

• Electric revenues increased by approximately $205 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 Condensed Consolidated Financial Statements). As a result of the amortization of the Settlement Regulatory Asset, the Utility's electric operating revenues increased by approximately $122 million for the three months ended June 30, 2004 as compared to the same period in 2003.

• DWR pass-through revenues decreased $120 million, or 21%, in the second quarter of 2004 as compared to the same period in 2003. This decrease was mainly due to a decrease in the Utility's DWR power charge remittance rate effective January 1, 2004, and a decrease in volume provided by the DWR contracts due to an increase in the amount of electricity purchased on the spot market in the second quarter of 2004 as compared to the same period in 2003.

• These increases were partially offset by a decrease in electric revenues due to an electric revenue over-collection in the same period in 2003. The Utility had an electric revenue over-collection of approximately $542 million in the second quarter of 2003 as a result of the lack of a regulatory recovery mechanism. The implementation of the rate design settlement provides the Utility with a regulatory recovery mechanism in 2004.

• Additionally, the CPUC-approved rate reduction in 2004 decreased the Utility's electric operating revenues by approximately $150 million for the three months ended June 30, 2004. The rate design settlement, effective January 1, 2004, implemented an annual electricity rate reduction of approximately $799 million.

• The remaining increase in the Utility's electric operating revenues was due to increases in the Utility's authorized revenue requirements for procurement and miscellaneous other electric revenues.

               For the six months ended June 30, 2004, the Utility's electric operating revenues increased approximately $439 million, or 13%, compared to the same period in 2003 due to the following factors:

• Electric revenues increased by approximately $205 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 Condensed Consolidated Financial Statements). As a result of the amortization of the Settlement Regulatory Asset, the Utility's electric operating revenues increased by approximately $246 million for the six months ended June 30, 2004 as compared to the same period in 2003.

• DWR pass-through revenues decreased $404 million, or 31%, for the six-month period ended June 30, 2004 as compared to the same period in 2003. This decrease was mainly due to a decrease in the Utility's DWR power charge remittance rate effective January 1, 2004 and a decrease in volume provided by the DWR contracts due to an increase in the amount of electricity purchased on the spot market in 2004.

• These increases were partially offset by a decrease in electric revenues due to an electric revenue over-collection in 2003. The Utility had an electric revenue over-collection of approximately $237 million for the six-month period ended June 30, 2003 as a result of the lack of a regulatory recovery mechanism. The implementation of the rate design settlement provides the Utility with a regulatory recovery mechanism in 2004.

• Additionally, electric revenues decreased by approximately $283 million for the six-month period ended June 30, 2004 due to the CPUC-approved rate reduction in 2004. The rate design settlement, effective January 1, 2004, implemented an annual electricity rate reduction of approximately $799 million.

• The remaining increase in the Utility's electric operating revenues was due to increases in the Utility's authorized revenue requirements for procurement 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 June 30,				Six months ended June 30,
(in millions)	2004		2003		2004		2003
Cost of purchased power	$	694	$	631	$	1,283	$	1,251
Proceeds from surplus sales allocated to the Utility	(35)		(95)		(98)		(133)
Fuel used in own generation	26		26		69		44
Total Cost of Electricity	$	685	$	562	$	1,254	$	1,162
Average cost of purchased power per kilowatt-hour	$	0.076	$	0.079	$	0.079	$	0.082
Total purchased power (gigawatt-hours)	9,185		7,972		16,279		15,238

               The Utility's cost of electricity increased approximately $123 million, or 22%, for the three months ended June 30, 2004, and approximately $92 million, or 8%, for the six months ended June 30, 2004, compared to the same periods in 2003. Increases in the cost of electricity for both periods were primarily due to an increase in the total volume of electricity purchased as a result of an extended refueling outage at the Utility's Diablo Canyon power plant in 2004.

Natural Gas Revenues

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

	Three months ended June 30,				Six months ended June 30,
(in millions)	2004		2003		2004		2003
Bundled gas revenues	$	615	$	590	$	1,482	$	1,354
Transportation service-only revenues	71		67		135		133
Total Natural Gas Revenues	$	686	$	657	$	1,617	$	1,487
Average bundled price of natural gas sold per Mcf	$	12.00	$	9.48	$	9.07	$	8.09
Total bundled gas sales (in millions Mcf)		51		62		163		167

               The Utility's natural gas operating revenues increased approximately $29 million, or 4%, for the three months ended June 30, 2004 and approximately $130 million, or 9%, for the six months ended June 30, 2004 compared to the same periods in 2003. Increases in natural gas operating revenues for both periods were a result of the approval of the Utility's 2003 GRC in May 2004 and an increase in the average cost of natural gas. These increases were partially offset by a decrease in the average volume of natural gas sold.

               The approval of the GRC resulted in an increase in natural gas revenues of approximately $87 million over the comparable periods in 2003 (see the 'Regulatory Matters' section of this MD&A), consisting of a 2004 portion totaling $35 million and a 2003 portion totaling $52 million.

               Excluding the effect of the GRC decision discussed above, the average bundled price of natural gas sold increased $0.87 per thousand cubic feet, or Mcf, or 9%, for the three months ended June 30, 2004 and $0.47 per Mcf, or 6% for the six months ended June 30, 2004, in comparison to the same periods in 2003. The Utility is permitted by the CPUC to pass along 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 June 30,				Six months ended June 30,
(in millions)	2004		2003		2004		2003
Cost of natural gas sold	$	247	$	288	$	790	$	738
Cost of gas transportation	31		32		67		68
Total Cost of Natural Gas	$	278	$	320	$	857	$	806
Average price of natural gas purchased per Mcf	$	4.84	$	4.65	$	4.85	$	4.42
Total natural gas purchased (in millions Mcf)		51		62		163		167

The decrease in the Utility's total cost of natural gas of approximately $42 million, or 13%, for the three months ended June 30, 2004 was due to a decrease in sales volume as a result of warmer weather in the period offset by an increase in the average market price of natural gas purchased. The decrease in sales volume of 11 million Mcf, or 18%, resulted in a $51 million decrease in the total cost of natural gas. The increase in the average market price of natural gas purchased of $0.19 per Mcf, or 4% resulted in a $9 million increase in the total cost of natural gas.

The increase in the Utility's total cost of natural gas of approximately $51 million, or 6 %, for the six months ended June 30, 2004 was due primarily to an increase in the average market price of natural gas purchased. The increase in the average market price of natural gas purchased of $0.43 per Mcf, or 10% resulted in a $70 million increase in the total cost of natural gas. This increase was offset by a decrease in sales volume of 4 million Mcf, or 2 % resulting in a $19 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 and six-month periods ended June 30, 2004, the Utility's operating and maintenance expenses increased $34 million, or 5%, and $116 million, or 8%, respectively, as compared to the same periods in 2003.

               The increase in operating and maintenance expenses in the three-month period ended June 30, 2004, as compared to the same period in 2003, is primarily due to escalating costs related to wage increases and higher expenses related to the refueling of Diablo Canyon.

               The increase in operating and maintenance expenses in the six-month period ended June 30, 2004, as compared to the same period in 2003, is primarily due to higher costs for environmental matters resulting from reassessments of the estimated liability for various sites, an increase in expenses related to the various provisions of the Settlement Agreement, including obligations to invest in clean energy technology and the donation of land, and higher expenses related to the refueling of Diablo Canyon.

Interest Expense

              The Utility's interest expense decreased approximately $66 million, or 29%, for the three months ended June 30, 2004, and approximately $72 million, or 16% for the six months ended June 30, 2004, compared to the same periods in 2003 due to a lower average amount of unpaid debts accruing interests and a lower weighted average interest rate on debt outstanding during the period.

Income Tax Expense

              The Utility's tax expense decreased approximately $50 million, or 24%, for the three months ended June 30, 2004 compared to the same period in 2003, mainly due to the recognition of tax regulatory assets provided for in rates established by the Utility's 2003 GRC.

              For the six months ending June 30, 2004, the Utility's tax expense increased approximately $2.1 billion, as compared to the same period in 2003, mainly due to the increase in pre-tax income of approximately $5.4 billion for the six months ended June 30, 2004 as compared to the same period in 2003.

PG&E Corporation, Eliminations and Others

Operating Revenues and Expenses

               PG&E Corporation's revenues consist mainly of billings to its affiliates 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 second quarter of 2004, PG&E Corporation's operating expenses increased by approximately $36million for the three-month and approximately $72 million for the six-month periods ending June 30, 2004,compared to the same periods in 2003. These increases were primarily due to increased external legal fees and other expenses related to NEGT's Chapter 11 proceeding, the Utility's Chapter 11 costs and other administrative expenses in 2004.

Interest Expense

               PG&E Corporation's interest expense is not allocated to its affiliates. In the second quarter of 2004, PG&E Corporation's interest expense decreased by approximately $18 million, or 50%, compared to the same period in 2003. For the six months ended June 30, 2004, PG&E Corporation's interest expense decreased by approximately $37 million, or 52%, compared to the same period in 2003. The decreases during these periods compared to the same periods in 2003 were mainly due to a reduction in principal amounts outstanding and a lower interest rate.

Other Expense

               In the second quarter of 2004, PG&E Corporation's other expense increased by approximately $35 million for the three-month and approximately $67 million for the six-month periods ending June 30, 2004, compared to the same periods in 2003. These increases during both periods were primarily due to a $32 million first quarter and $33 million second quarter pre-tax charge to earnings 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 June 30, 2004, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $1.4 billion, and restricted cash of approximately $2.5 billion. PG&E Corporation and the Utility maintain separate bank accounts. At June 30, 2004, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $858 million and restricted cash of $361 million. At June 30, 2004 the Utility had cash and cash equivalents of approximately $553 million, and restricted cash of approximately $2.1 billion. 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 Condensed 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.

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

Operating Activities

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

	Six months ended June 30,
(in millions)	2004		2003
Net income	$	3,486	$	272
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	650		605
Recognition of regulatory assets, net of tax	(2,904)		-
Change in other working capital	287		(79)
Other uses of cash:
Payments authorized by the bankruptcy court on amounts classified as     liabilities subject to compromise	(1,022)		(62)
Other changes in operating assets and liabilities	123		468
Net cash provided by operating activities	$	620	$	1,204

               Net cash provided by operating activities decreased by approximately $584 million during the six months ended June 30, 2004, compared to the same period in 2003. This decrease was mainly due to the net impact of the following factors:

• Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise increased approximately $960 million during the six months ended June 30, 2004, compared to the same period in 2003. This increase was the result of the payment of all allowed creditor claims on the Effective Date.

• An increase in net income for the six months ended June 30, 2004, of approximately $310 million, excluding the one-time non-cash gain, after-tax, of approximately $2.9 billion related to the recognition of the Settlement regulatory assets.

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 six months ended June 30, 2004.

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

	Six months ended June 30,
(in millions)	2004		2003
Capital expenditures	$	(737)	$	(730)
Net proceeds from sale of assets	25		11
Increase in restricted cash	(1,834)		-
Other investing activities	(54)		13
Net cash used by investing activities	$	(2,600)	$	(706)

               Net cash used by investing activities increased by approximately $1.9 billion during the six months ended June 30, 2004, compared to the same period in 2003. This increase was mainly due to the following factors:

• An increase in restricted cash of approximately $1.8 billion during the six months ended June 30, 2004, compared to the same period in 2003, mainly due to funds deposited into escrow to pay disputed claims when resolved; and

• An increase in nuclear decommissioning funding of approximately $44 million.

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 six months ended June 30, 2004, and 2003 were as follows:

	Six months ended June 30,
(in millions)	2004		2003
Net proceeds from issuance of long-term debt	$	6,892	$	-
Long-term debt issued, matured, redeemed or repurchased		(7,098)		-
Rate reduction bonds matured	(141)		(141)
Dividends paid	(88)		-
Preferred stock with mandatory redemption provisions redeemed	(11)		-
Net cash used by financing activities	$	(446)	$	(141)

               For the six months ended June 30, 2004, net cash used by financing activities increased by approximately $305 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.

• 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 $7.1 billion of long-term debt, and deposit funds into escrow for the payment of disputed claims.

• On June 29, 2004, the Utility entered into four separate loan agreements, each dated as of June 1, 2004, with the California Pollution Control Financing Authority, which issued $345 million aggregate principal amount of its Pollution Control Refunding Revenue Bonds.

• Approximately $88 million of preferred stock dividends were paid during the six months ended June 30, 2004.

• Approximately $11 million of preferred stock with mandatory redemption provisions was redeemed on April 12, 2004.

PG&E Corporation

               At June 30, 2004, PG&E Corporation had stand-alone cash and cash equivalents of approximately $858 million 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 half of 2004 or 2003. PG&E Corporation also has approximately $361million of restricted cash that is recorded in noncurrent assets at June 30, 2004. This restricted cash pertains to the tax dispute with NEGT described above.

Operating Activities

               PG&E Corporation's cash flows from operating activities consist mainly of billings to its affiliates 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 six months ended June 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 six months ended June 30, 2004, and 2003 were as follows:

	Six months ended June 30,
(in millions)	2004		2003
Net income (loss)	$	3,405	$	(127)
Loss from discontinued operations	-		366
Cumulative effect of changes in accounting principles	-		6
Net income (loss) from continuing operations	3,405		245
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	651		598
Recognition of regulatory asset	(4,900)		-
Deferred income taxes and tax credits, net	2,053		300
Other deferred charges and noncurrent liabilities	12		484
Other changes in operating assets and liabilities	(510)		(126)
Net cash provided by operating activities	$	711	$	1,501

               Net cash provided by operating activities decreased by $790 million during the six months ended June 30, 2004, compared to the same period in 2003. This decrease was primarily related to decreases in other deferred charges and noncurrent liabilities and restricted cash, partially offset by the Utility's increase in net cash provided from operating activities as discussed above.

Investing Activities

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

Financing Activities

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

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

	Six months ended June 30,
(in millions)	2004		2003
Net proceeds from issuance of long-term debt	$	6,892	$	-
Long-term debt matured, redeemed or repurchased	(7,098)		-
Rate reduction bonds matured	(141)		(141)
Preferred stock with mandatory redemption provisions redeemed	(11)		-
Dividends paid	(88)		-
Common stock issued	97		54
Net cash provided (used) by financing activities	$	(349)	$	(87)

               PG&E Corporation's net cash used by financing activities increased by $262million for the six months ended June 30, 2004, compared to the same period in 2003. This increase was primarily related to the Utility's financing activities as discussed above, partly offset by the increase in cash received from the sale of common stock.

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 June 30, 2004, the Utility did not have any borrowings under either facility. Under the $850 million facility, $191 million was outstanding as letters of credit at June 30, 2004.

               The Utility expects that the cash it retains after its emergence from Chapter 11, 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.

Dividends and Share Repurchases

               Historically, in determining whether to, and at what level to, declare a dividend, PG&E Corporation has considered a number of financial factors, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk, as well as other factors, including the regulatory and legislative environment, operating performance, and capital and financial resources in general. PG&E Corporation did not declare or pay a dividend during the Utility's Chapter 11 proceeding. Further, until the 6⅞% Senior Secured Notes issued by PG&E Corporation are redeemed or rated Baa3 or better by Moody's and BBB- or better by 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 f unded 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.

               While in Chapter 11, the Utility was prohibited from paying any common or preferred dividends without bankruptcy court approval. The Utility resumed the payment of preferred 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 will be payable August 15, 2004 to the shareholders of record on July 30, 2004. The Utility does not expect to resume paying common stock dividends until it achieves the target capital structure of 52% equity as provided under the Settlement Agreement.

               PG&E Corporation has previously disclosed that it aspires to resume paying dividends to its shareholders in the second half of 2005. Under certain scenarios, such as a scenario in which Energy Recovery Bonds in the approximate amount of $1.8 billion are issued in January 2005, PG&E Corporation may be in a position to resume the payment of dividends in the first half of 2005.

               PG&E Corporation has forecasted that about $3 billion in cash would be available for dividends to, and share repurchases from, its shareholders in the period 2005 through 2008, as well as for the potential to make additional investments in the Utility's business based on various assumptions including:

• that the Utility earns its full authorized rate of return throughout the period;
• that actual cash from operations during this period are equal to forecasted amounts;
• that actual capital expenditures during this period are equal to forecasted amounts (forecasted amounts do not include amounts for new generation development or implementation of an advanced metering system);
• that the Utility will make distributions to PG&E Corporation as forecasted; and
• that other events do not occur that would change management's view as to the prudent level of cash conservation.

               If any of these assumptions proves to be inaccurate, actual cash available for dividends or share repurchases could vary materially.

CAPITAL EXPENDITURES AND COMMITMENTS

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

               During the six-month period ended June 30, 2004, the Utility entered into various agreements to purchase energy. Under these agreements, the Utility is committed to make energy payments of approximately $277 million and capacity payments of approximately $28 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 had obtained unsecured credit lines from the majority of its gas supply counterparties.

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

(in millions)
2004	$	499
2005	301
2006	26
2007	7
2008	-
Thereafter	-
Total	$	833

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 complete 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 are also diversified, ranging from fixed prices to market based prices to base prices that are escalated using published indices.

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

(in millions)
2004	$	118
2005	28
2006	29
2007	38
2008	30
Thereafter	64
Total	$	307

Transmission Control Agreement

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

               At June 30, 2004, the ISO had RMR agreements for which the Utility could be obligated to pay the ISO an estimated $623million in net costs during the period July 1, 2004, to June 30, 2006. These costs are recoverable under 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 approving rates that, if affirmed by the FERC, would require the subsidiaries of Mirant Corporation, or Mirant, that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $340 million, including interest, for availability of Mirant's RMR Plants under these agreements. However, 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 on this issue, what the FERC's decision will be, and the amount of any refunds, which may be impacted by Mirant's Chapter 11 filing. It is uncertain how the resolution of this matter would be reflected in rates.

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.

Transition from Frozen Rates to Cost of Service Ratemaking

               Frozen electricity rates, which began on January 1, 1998, were designed to allow the Utility to recover its authorized utility costs and to the extent frozen rates generated revenues in excess of these costs, to recover the Utility's costs of transitioning to a competitive market. Although the surcharges implemented in 2001 effectively increased the actual rate under the frozen rate structure, changes in the Utility's authorized revenue requirements did not impact the Utility's revenues. In addition, DWR revenue requirements reduced the Utility's revenues under the frozen rate structure. As a result of revised electricity rates discussed below and a January 2004 CPUC decision determining that the rate freeze ended on January 18, 2001, effective January 1, 2004, the Utility's rates are intended to reflect cost of service whereby the Utility's rates are based on the sum of individual components. Changes in any indi vidual revenue requirement will change customers' electricity rates.

               In February 2004, the CPUC issued a decision approving a rate design settlement to implement an annual electricity rate reduction of approximately $799 million. Because the Utility's customers' bills did not reflect the rate reduction until March 1, 2004, the Utility accrued a customer refund obligation of approximately $100 million at March 31, 2004, representing revenues received during January and February in excess of those revenues that would have been charged had the rate reduction been implemented on January 1, 2004. As of June 30, 2004, the Utility had refunded approximately $95 million of this refund obligation to customers.

               In May 2004, the CPUC issued a decision in the Utility's 2003 GRC (see "2003 General Rate Case" below). Other pending proceedings and applications which will impact the Utility's rates are discussed below and include:

· The Utility's cost of capital application;

· Electric transmission rate cases;

· Pending energy supplier refunds, claim offsets or other credits pursuant to the Settlement Agreement;

· The calculation of any over-collection of the surcharge revenues for 2003;

· The allocation of the DWR's 2004 revenue requirements. Because the Utility is on cost-of-service ratemaking and because amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues, changes in the DWR's revenue requirements are not expected to have a material impact on the Utility's results of operations; and

· The Utility's application to refinance the remaining unamortized pre-tax balance of the Settlement Regulatory Asset by issuing Energy Recovery Bonds (see Note 2 of the Notes to the Condensed Consolidated Financial Statements for further discussion).

2003 General Rate Case

               On May 27, 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 approves 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
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
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, the Utility has recorded various regulatory assets and liabilities associated with revenue requirement increases, recovery of retained generation assets and unfunded taxes, depreciation, and decommissioning. The net impact of these items on a pre-tax basis for the three and six-month periods ended June 30, 2004 is as follows:

(in millions)	2003		2004		Previously Recorded		Net 2004 Adjustment
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 began recording 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 has 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 has recorded both the 2003 and 2004 natural gas distribution revenue requirement increase 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 has 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 April 2004, a CPUC ALJ issued a proposed decision, which would approve certain storm response improvement initiatives as well as the funding for these initiatives. In early July 2004, a revised proposed decision was issued that would modify the CPUC's existing reliability standard to require the Utility to meet improved reliability targets, but did not specify any particular penalties if the Utility failed to meet those targets. On June 24, 2004, an alternate proposed decision was issued that would adopt a reliability performance incentive mechanism for the years 2005 through 2007 but with more stringent reliability performance targets than proposed by the Utility. Under the proposed performance incentive mechanism the Utility could receive up to $42 million each year depending on the extent to which the Utility exceeded the reliability performance improvement targets, but could be required to pay a penalty of up to $42 million a year depending on the extent to which it failed to meet the targets. Neither the revised proposed decision nor the alternate proposed decision would provide the Utility with additional revenues to meet the more stringent reliability standards. If either the revised proposed decision or the alternate proposed decision is issued, there is an increased risk that the Utility would incur a penalty if it failed to meet the new performance reliability targets. The CPUC is expected to issue a final decision in the third quarter of 2004.

Cost of Capital Proceedings

               For its electricity and natural gas distribution operations, natural gas transmission and storage, and electricity generation operations, the Utility's currently authorized return on equity is 11.22% and its currently authorized cost of debt is 7.57%. The Utility's currently authorized capital structure is 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 its (1) actual cost of capital 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. The application also requests authorization for the Utility's forecast cost of capital and capital structure for 2005. In this application, the Utility has requested the following cost of capital for its utility operations in 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. In the second quarter of 2004, the Utility recorded a $33 million reserve against operating revenues for the difference between its currently authorized rate of return and the lower rate of return required in its cost of capital application.

                For 2005, the requested capital structure reflects an assumption that Energy Recovery Bonds 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 Energy Recovery Bonds targeted for issuance in January 2005 is approximately $1.8 billion. After the issuance of Energy Recovery Bonds, 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 Energy Recovery Bonds from customers through the dedicated rate compone nt.

                The Utility has proposed to include any electric revenue requirement change authorized in this proceeding in rates effective January 1, 2005. The Utility 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 procedural schedule in the cost of capital proceeding calls for a proposed decision by October 28, 2004 allowing a final decision to be issued by the CPUC in December 2004.

DWR Revenue Requirements

               The DWR filed a proposed $4.5 billion 2004 power charge revenue requirement and a proposed 2004 bond charge revenue requirement of approximately $873 million with the CPUC in September 2003. In January 2004, the CPUC issued a decision that adopted an interim allocation of the DWR's proposed 2004 revenue requirements among the three California investor-owned electric utilities' 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 kilowatt-hour, or kWh, basis, which resulted in approximately $369 million being allocated to the Utility's customers. SCE filed a petition to modify the CPUC's approach for allocating the DWR's bond charges, requesting that more be allocated to the Utility's customers. In May 2004, the CPUC denied SCE's petition, effectively reaffirming the equal cents per kWh allocation of the DWR bond charge revenue requirement.

               The CPUC is considering adopting a multi-year allocation of the DWR's power charge revenue requirements in a second phase of the 2004 DWR power charge proceeding. If adopted, a multi-year allocation would replace the interim allocation for 2004. In April 2004, the Utility filed with the CPUC a settlement agreement reached with SCE and The Utility Reform Network, or TURN, on the allocation of the DWR's power charge revenue requirement for 2004 and beyond. Hearings on the settlement were completed in June 2004. In July 2004, two proposed decisions were issued in this matter. The proposed decisions incorporate the DWR's supplemental determination of its 2004 revenue requirements, discussed below. Neither of the proposed decisions recommends adoption of the settlement agreement. Neither of the proposed decisions would significantly change the amount of DWR's 2004 power charge revenue requirements allocated to the Utility's customers. However, the Utility cannot predict the final outcome of this matter.

              In April 2004, the DWR submitted the Supplemental Determination of its 2004 revenue requirements to the CPUC for allocation among the three California investor-owned utilities. The Supplemental Determination would reduce 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 May 2004, the DWR issued a letter to the CPUC proposing various methodologies to implement its Supplemental Determination, including issuing one-time bill credits to bundled customers, reducing the DWR power charge rates, or using $245 million to redeem outstanding DWR bonds. The proposed decisions described above assume that the reduction will be used to lower DWR power charge rates. However, the Ut ility 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, including the reduction in the 2004 revenue requirement related to 2001 through 2002, is not expected to 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 u ntil 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 will examine 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. At June 30, 2004, the ERRA had an under-collected balance of approximately $102.5 million, which is below the 5% trigger for mandatory adjustment of rates. This balance will be adjusted downward to reflect the decision issued by the CPUC on June 9, 2004, adopting an interim ERRA revenue requirement of $2.189 billion for 2004. The Utility has submitted an advice letter to the CPUC to implement the rate changes associated with the approved interim revenue requirement. 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 in September 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.

               In April 2004, the CPUC's Office of Ratepayer Advocates, or ORA, issued a report in the Utility's ERRA proceeding reviewing procurement activities during the period from January 1, 2003 through May 31, 2003. The ORA did not recommend any disallowances, but did ask the Utility to provide additional information in future ERRA filings. Additionally, the report indicates that an audit of ERRA entries was not performed but that the ORA intends to perform a full financial audit of the Utility's procurement activities in future ERRA proceedings. 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 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 by 2008 and an additional 1,000 MW by 2010. The Utility has proposed to release drafts of these two requests for offers, or RFO, for public comment in September 2004 and to issue the RFO's in October 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 RFO no later than June 2005. The Utility also has requested that, at the time the CPUC approves a proposal for a new utility-owned generation facility, the CPUC also authorize a reasona ble cost for the facility to be placed in rate base. After consideration of new customer energy efficiency programs and an increase in purchase of renewable energy (as further discussed below), 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.

               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 LSE's.

               The Utility also has proposed:

• New customer energy efficiency (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.  

               The Utility has assumed that by 2014 its load and corresponding 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.

               Finally, the California Governor has called upon the CPUC to revisit its January 2004 interim decision establishing the long-term regulatory framework under which the California investor-owned electric utilities are required to plan for and procure energy resources. Among other requirements, the decision requires the utilities to achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by January 1, 2008. The California Governor has requested that the CPUC accelerate the phase-in of the planning reserve requirement to 2006. The CPUC is considering comments it solicited about whether it should adopt the accelerated phase-in. An accelerated phase-in of the planning reserve requirement will increase the amount of the electric resource commitments that the Utility would be required to make.

               The Governor also 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. 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 Proceeding

               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. In December 2002, a FERC ALJ issued an initial decision finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001 (the only time period for which the FERC permitted refund claims), but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

               In an October 2003 decision, the FERC confirmed most of the ALJ's findings, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the Power Exchange, or 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 December 2004. The PX cannot make its compliance filing until after the ISO makes its filing. The actual refunds will not be determined until the FERC issues a final decision, following the ISO and PX compliance filings. The FERC is uncertain when it will issue a final decision in this proceeding, after which appellate review is expected. In addition, future refunds could increase or decrease as a result of retroactive adjustment proposed by the ISO, which incorporate revised data provided by the Utility and other entities. The FERC has indicated that it does not have the power to direct refunds for the period before October 2, 2000, but has engaged in an investigation of market manipulation and sought through settlement or hearings disgorgement of profits for any tariff violations during this period. Unless settled among the various entities, this conclusion will also be subject to judicial review. On July 27, 2004, the U.S. Court of Appeals for the Ninth Circuit issued an order allowing a lawsuit brought by the CPUC and SCE challenging the FERC's refund period for California power purchases to proceed.

               The Utility and other California agencies have entered into settlement agreements with some sellers, and have initiated settlement discussions with many market participants to attempt to resolve amounts due to California and the Utility. Settlement discussions with a number of major sellers are continuing. A settlement conference was held June 30, 2004, at the FERC, which laid out the framework for how the settlements may proceed. Subsequently, individual meetings with a number of market participants have occurred. The Utility cannot predict whether these settlement negotiations will be successful or whether further litigation may occur in connection with claimed refunds and recovery of excessive charges.

               Under the Settlement Agreement, the Utility and PG&E Corporation agreed to continue to cooperate with the CPUC and the state of California in seeking refunds from generators and other energy suppliers. The net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relating to the Utility's ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offset will reduce the balance of the Settlement Regulatory Asset.

               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 October 2003 decision could further reduce the amount of the suppliers' claims by several hundred million dollars. However, this reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology. 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 related to this FERC proceeding described below. The net after-tax amounts received by the Utility under these settlements will result in a reduction to the Utility's Settlement Regulatory Asset.

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.

               The Utility will refund the natural gas payment received from El Paso to core procurement customers in the third quarter of 2004. 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 Condensed 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 FERC approved settlement on July 2, 2004. Under the Williams settlement, the Utility will receive an after-tax credit of approximately $40 millionthat will reduce the Settlement Regulatory Asset and other regulatory balancing accounts. The Utility must seek approval from the bankruptcy court to realize the after-tax credit associated with this settlement.

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. In order for this settlement to become effective, it must first be approved by the CPUC and the FERC. If the Dynegy 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 Proceeding" above. A definitive agreement to implement the settlement was filed with the FERC on June 28, 2004 and is pending approval. The Utility expects that the Dynegy settlement will be approved in the third quarter of 2004.

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 CPUC and the FERC. The Utility plans to file a definitive agreement to implement the settlement with the FERC by August 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 b y the FERC in the pending refund proceeding discussed under "FERC Proceeding" above. The CPUC decision approving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the amounts actually received by the Utility under pending settlements with energy suppliers, including Duke.

               The CPUC decision approving the rate design settlement provides for regulatory balancing account treatment to ensure that the amount of the revenue requirement reduction is adjusted to reflect the net after-tax amounts actually received by the Utility under pending settlements with energy suppliers, including the settlements discussed above.

Natural Gas Supply and Transportation

               The Utility's natural gas transportation and storage rate case application requests a $434 million revenue requirement for 2005, representing an approximately $2 million reduction from the 2004 revenue requirement. This application also proposes certain limited rate design changes in order to provide the Utility the opportunity to fully recover the Utility's cost of providing local transmission service. On June 29, 2004, the ORA, filed its recommendation proposing an overall revenue requirement of $424 million, representing a $10 million decrease from the amount requested by the Utility. A CPUC decision is expected by the end of 2004.

               The Utility is at risk of not recovering its natural gas transportation and storage costs and does not have regulatory balancing account provisions for over-collections or under-collections of natural gas transportation or storage revenues. The Utility may experience a material reduction in operating revenues if throughput levels or market conditions are significantly less favorable than reflected in rates for these services.

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.

               Because these costs did not meet the applicable accounting probability standard under SFAS No. 71 needed to record regulatory assets, the Utility has not recorded a regulatory asset for the costs it has incurred as of June 30, 2004. PG&E Corporation and the Utility are unable to predict the ultimate outcome of this proceeding.

Spent Nuclear Fuel Storage Proceedings

               Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy, or 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 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 NR C granted authorization in early 2004. However, several intervenors in that proceeding filed an appeal of the NRC's decision in the U.S. Court of Appeals for the Ninth Circuit. Oral arguments on that appeal are expected in the fall of 2004 with a decision anticipated in the spring 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. In the spring of 2004, San Luis Obispo County issued a permit to the Utility, which contained a number of conditions. The Utility, along with several other interested parties, have filed appeals of the permit with the California Coastal Commission. Those appeals are expected to be decided by the end of 2004. If the dry cask storage facility is not approved or is delayed, the Utility also plans to pursue NRC approval of another storage option to install a temporary rack in each unit that would increase the on-site storage capability t o permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. 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 energy efficiency program activities and public purpose programs. These applications remain subject to verification and approval by the CPUC. The CPUC has only authorized the Utility to recognize an insignificant amount of these incentives in its results of operations. There are a number of forward-looking proceedings regarding program administration and 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

               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 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 marked to market on PG&E Corporation's Consolidated Statements of Operations 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). From the issuance date of the Convertible Notes on June 25, 2002, through December 31, 2003, the fair value of the dividend participation rights component was considered immaterial. At June 30, 2004, the estimated fair value of the dividend participation rights component was $65.2 million, an increase in value of $19.6 million, net of taxes, from March 31, 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; and

· Planning reserve and operating requirements.

               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 2007 to 2010 when it is assumed that there will 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, adverse 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 50% 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 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 inco me.

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 $3.2 million at June 30, 2004 and $4.8 million at June 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 six months of 2004 was approximately $6.4 million, $1.9 million and $3.6 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 June 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 $2.1 billion at June 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 $58 million at June 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.

               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 or obtain 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 six months of 2004, the Utility recognized no material losses due to contract defaults or bankruptcies. At June 30, 2004, there were three counterparties that represented greater than 10% of the Utility's net wholesale credit exposure. These three investment grade counterparties represented a total of approximately 64% 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.

CRITICAL ACCOUNTING POLICIES

               The preparation of Consolidated Financial Statements in accordance with accounting principles generally accepted in the United States of America, or 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. 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 a natural gas pipeline expansion project. 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 record 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 June 30, 2004, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of approximately $7.6 billion and regulatory liabilities (including current balancing accounts payable) of approximately $4.3 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 the same impact on the Utility's results of operations that they had in prior years.

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 June 30, 2004, the Utility's accrual for undiscounted environmental liability was approximately $340 million. The Utility's undiscounted future costs could increase to as much as $455 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.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

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

               In May 2004, 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-b, "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 related to the Prescription Drug Act. FSP 106-2 is effective for the third quarter of 2004, which begins on July 1, 2004. According to an actuarial assessment, the Utility's postretirement healthcare benefit plan does not qualify for the federal subsidy included in the Prescription Drug Act. However, FSP 106-2 is also expected to have an impact on an employer's per capita claim costs and future plan participation rates. PG&E Corporation and the Utility are currently evaluat ing the impact on per capita claim costs and future plan participation rates.

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 $76 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.

               PG&E Corporation is reviewing a report recently issued by the IRS regarding its audit of PG&E Corporation's 1999 and 2000 consolidated federal income tax returns. In the fourth quarter of 2003, PG&E Corporation made an advance payment to the IRS of $75 million to halt the accrual of interest in respect to these tax returns. PG&E Corporation does not expect final resolution of this audit to have a material impact on its financial position or results of operations.

               As a result of NEGT's Chapter 11 filing on July 8, 2003, the IRS is auditing PG&E Corporation's 2001 and 2002 consolidated federal income tax returns. One of NEGT's subsidiaries operated two synthetic fuel facilities in 2001 and most of 2002. If certain criteria are met, including a requirement that the coal waste actually undergo a chemical change to qualify as a synthetic fuel, a tax credit may be taken. The IRS issued a private letter ruling to this NEGT subsidiary finding that the chemical change requirement had been met. Although the IRS previously announced it would review scientific tests to determine compliance with the chemical change requirement, it has more recently announced that it will not challenge the tax credit based on the chemical change requirement if it has already issued a private letter ruling to a company on the chemical change requirement. However, the IRS will still verify whether t he company's representations upon which the ruling was granted can be substantiated. In addition, the IRS can challenge the tax credit based on a failure to meet the other criteria.

               PG&E Corporation has claimed tax credits totaling approximately $104 million for these facilities. If the IRS determines that these synthetic fuel facilities do not meet the criteria to qualify for the tax credit, PG&E Corporation may be subject to additional tax and interest.

               All 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.

               Through June 30, 2003, PG&E Corporation increased its valuation allowance against certain state deferred tax assets related to NEGT or its subsidiaries due to the uncertainty in their realization. Valuation allowances of approximately $7 million for the three-month and $24 million for the six-month periods ending June 30, 2003, were recorded in discontinued operations, and approximately $5 million in accumulated other comprehensive loss through June 30, 2003.

               PG&E Corporation will not recognize additional income tax benefits for financial reporting purposes after July 7, 2003 with respect to any subsequent losses related to NEGT or its subsidiaries even though it continues to include NEGT and its subsidiaries in its consolidated income tax returns. Any such recognized benefits and deferred tax assets arising from losses related to NEGT or its subsidiaries that have been recognized through July 7, 2003, will be recorded in discontinued operations in the Consolidated Statements of Operations at the time that PG&E Corporation releases its ownership interest in NEGT.

               NEGT and its creditors have brought litigation against PG&E Corporation in NEGT's Chapter 11 proceeding, asserting that NEGT is entitled to be compensated under an alleged implied tax sharing agreement between PG&E Corporation and NEGT for any tax savings achieved by PG&E Corporation as a result of the incorporation of losses and deductions related to NEGT or its subsidiaries in PG&E Corporation's consolidated federal tax return. This litigation is discussed in the "NEGT - NEGT's Chapter 11 Filing" above.

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 June 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's, 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 June 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 June 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."

               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 bankruptcy. The Plan of Reorganization incorporated the terms of the settlement agreement approved by the California Public Utilities Commission, or 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 will no longer be subject to the oversight of the bankruptcy court, the bankruptcy court will retain 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 Reorganiz ation. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims. For information regarding the implementation of the Plan of Reorganization, see Note 2 of the Notes to the Condensed Consolidated Financial Statements.

               As previously disclosed, on March 16, 2004, the CPUC denied the applications filed by various parties to rehear and reconsider its December 18, 2003 decision approving the Settlement Agreement. In addition, the two CPUC commissioners who did not vote to approve the Settlement Agreement, or the dissenting commissioners, and the City of Palo Alto filed appeals of the bankruptcy court's confirmation order in the U.S. District Court for the Northern District of California, or the District Court, citing similar objections to those included in the request for rehearing and reconsideration of the CPUC's decision. On July 15, 2004, the District Court dismissed the dissenting commissioners' appeal of the bankruptcy court's order confirming the Plan of Reorganization. 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. The City of Palo Al to's appeal of the confirmation order remains pending at the District Court.

               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 (1) the CPUC's December 18, 2003 decision approving the Settlement Agreement and (2) the CPUC's March 16, 2004 denial of their applications for rehearing of the CPUC's December 18, 2003 decision. CCSF and Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF requests the appellate court to hear and review the CPUC's decisions approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. On July 16, 2004, three California state senators filed a request for permission to file a brief in support of CCSF's and Aglet's petitions. The California Court of Appeal has not acted yet on the petitions or the state senators' request. PG&E Corporation and the Utility believe the petitions are without merit and should be denied. The Utility filed its answer in opposition to the petitions for review on May 19, 2004.

Chapter 11 Filing of NEGT

               For 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 Condensed Consolidated Financial Statements.

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

               As required by the U.S. Court of Appeals for the Ninth Circuit, the parties in the filed rate case litigation filed a status report with the court on July 28, 2004. For more information regarding the Filed Rate Case litigation, 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.

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 quarter 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 quarter 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 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 Corporation and the holding companies of the other majo r 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 has appealed the decision of the California Court of Appeal finding that the CPUC had limited jurisdiction to the California Supreme Court.

               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 quarter ended March 31, 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 June 30, 2004, warrantholders had exercised, on a net exercise basis, warrants to purchase 3,015,937 shares, and had received 3,014,765 shares of PG&E Corporation common stock.

              On April 12, 2004, Pacific Gas and Electric Company, or the Utility, redeemed 300,000 shares of its 6.57% series of First Preferred Stock at a redemption price of $25.3825 and 125,000 shares of its 6.30% series of First Preferred Stock at a redemption price of $25.315. The redemption prices include any accumulated and unpaid dividends existing as of the redemption date.

               As previously disclosed, on February 18, 2004, the Board of Directors of PG&E Corporation authorized the amendment of the Rights Agreement, or Rights Agreement, dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, or Rights Agent, by providing that the rights to purchase one one-hundredth of a share of PG&E Corporation's Series A Preferred Stock, par value $100 per share, that were distributed to PG&E Corporation's shareholders on December 20, 2000, would expire on the close of business on the date that the Utility's Plan of Reorganization becomes effective.

               On April 12, 2004, the Utility's Plan of Reorganization became effective and the rights to purchase one one-hundredth of a share of PG&E Corporation's Series A Preferred Stock, par value $100 per share, expired.

               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 3. DEFAULTS UPON SENIOR SECURITIES

               At the time of Pacific Gas and Electric Company's, or the Utility's, Chapter 11 filing on April 6, 2001, the Utility had defaulted on $873 million of commercial paper outstanding and had drawn and had outstanding $938 million under its bank credit facility, which was also in default. As authorized by the bankruptcy court, starting in May 2002, the Utility has made past due and current interest payments on its commercial paper and bank credit facility.

               With regard to certain pollution control bond-related debt of the Utility, the Utility had defaulted under the credit agreements with the banks that provide letters of credit as credit and liquidity support for the underlying pollution control bonds. These defaults included the Utility's non-payment of other debt in excess of $100 million, the Utility's filing of a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code, and non-payment of interest. As a result of these defaults, several of the letters of credit banks caused the acceleration and redemption of four series of pollution control bonds. All of these redemptions were funded by the letters of credit banks. The total principal of the bonds (and related loans) accelerated and redeemed in April and May 2001 was $454 million. As authorized by the bankruptcy court, starting in May 2002, the Utility made past-due and current interest payment s on these loans.

               In 2002, the Utility paid advances and interest on advances to banks providing letters of credit on pollution control bonds series 96C, 96E, 96F, and 97B. As authorized by the bankruptcy court, starting in June 2002, the Utility also paid past-due interest advances and monthly interest. As authorized by the bankruptcy court, the Utility also made semi-annual interest payments on pollution control bond series 96A backed by bond insurance. With regard to certain pollution control bond-related debt of the Utility backed by the Utility's mortgage bonds, an event of default occurred under the relevant loan agreements with the California Pollution Control Financing Authority due to the Utility's Chapter 11 filing. The Utility obtained bankruptcy court approval to make regular payments on its mortgage bonds and consequently the debt service payments on these bonds were passed through to the pollution control bondholders .

               The Utility's filing of a Chapter 11 petition also constituted a default under the indenture that governed its medium-term notes ($287 million aggregate amount outstanding), five-year 7.375% senior notes ($680 million aggregate amount outstanding), and floating rate notes ($1.24 billion aggregate amount outstanding). As authorized by the bankruptcy court, starting in May 2002, the Utility paid past-due and current interest payments on its medium-term notes, its 7.375% senior notes, and its $1.24 billion floating rate notes. The Utility did not make a principal payment of $1.24 billion on its 364-day floating rate notes at maturity.

               Prior to April 12, 2004, the date of the Utility's emergence from Chapter 11, the Utility had not made principal payments on unsecured long-term debt of $181 million.

               With regard to the 7.90% Quarterly Income Preferred Securities, or QUIPS, and the related 7.90% Deferrable Interest Debentures, or Debentures, the Utility's filing of a Chapter 11 petition was an event of default under the applicable indenture. Pursuant to the related trust agreement, the trustee was required to take steps to liquidate the trust and distribute the Debentures to the QUIPS holders. Pursuant to the trustee's notice dated April 24, 2002, the trust was liquidated on May 24, 2002. Upon liquidation of the trust, the former holders of QUIPS received a like amount of 7.90% Deferrable Interest Subordinated Debentures, or QUIDS. As authorized by the bankruptcy court, starting in May 2002, the Utility made past-due and current interest payments on the QUIDS. The QUIDS were paid in full on the effective date of the Utility's Plan of Reorganization.

               The Utility has authorized 75 million shares of First Preferred Stock ($25 par value) and 10 million shares of $100 First Preferred Stock ($100 par value), which may be issued as redeemable or non-redeemable preferred stock. (The Utility has not issued any $100 First Preferred Stock.) At June 30, 2004, the Utility had issued and outstanding 5,784,825 shares of non-redeemable preferred stock and 11,048,456 shares of redeemable preferred stock. The Utility's redeemable preferred stock is subject to redemption at the Utility's option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. The Utility's redeemable preferred stock with mandatory redemption provisions consists of 2.7 million shares of the 6.57% series and 2.375 million shares of the 6.30% series at June 30, 2004. At the Utility's option, the 6.57% series may be redeeme d beginning 2002 and the 6.30% series may be redeemed beginning in 2004 at par value plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of stock outstanding. At June 30, 2004, the redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions are approximately $4 million per year for 2002, 2003, and 2004 for the 6.57% series, and $3 million per year beginning 2004 for the 6.30% series. The Utility is not permitted to make sinking fund payments unless all dividends on preferred stock have been paid. As discussed below, through March 31, 2004, the Utility's Board of Directors had not declared any preferred stock dividends since the dividend paid with respect to the period ended October 31, 2000. Therefore, the $4 million sinking fund payments that were due on July 31, 2002, and July 31, 2003, to redeem 150,000 shares per sinking fund payment of the 6.57% series were not made. The sinking fund payments are cumulative so that if on July 31 of any given year, the sinking fund payment is not made, the remaining shares of the 6.57% series required to be redeemed must be redeemed before the Utility can issue any shares of another series with a required sinking fund, unless the redemption of shares of both series is pro rata.

               Holders of the Utility's non-redeemable 5.0%, 5.5%, and 6.0% series of preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share.

               Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. Until cumulative dividends and cumulative sinking fund payments on its preferred stock are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock.

               On April 12, 2004, the Utility's Chapter 11 Plan of Reorganization became effective. In addition to other payments, the Utility paid approximately $83 million in preferred stock dividends and made sinking fund payments of approximately $10 million that were in arrears. The Utility's various series of preferred stock remain outstanding. The preferred stock has an aggregate par value of approximately $421 million, excluding the par value of the shares of 6.57% and 6.30% series of preferred stock that were redeemed on April 12, 2004.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On April 21, 2004, PG&E Corporation and Pacific Gas and Electric Company held their joint annual meeting of shareholders. Information regarding the voting results of the meetings is contained in PG&E Corporation and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, Part II, Item 4.

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 June 30, 2004, was 4.48. The Utility's earnings to combined fixed charges and preferred stock dividends ratio for the three months ended June 30, 2004, was 4.25. 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 333-10994 relating to various series of the Utility's first preferred stock and its senior secured bonds, respectively.

               PG&E Corporation's earnings to fixed charges ratio for the three months ended June 30, 2004, was 3.6. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and exhibit into PG&E Corporation's Registration Statement No. 333-114923 relating to its senior secured notes.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)  Exhibits:

3.1	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004, Exhibit 3)
3.2	Bylaws of PG&E Corporation dated as of April 21, 2004 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2004, Exhibit 3.2)
3.3	Bylaws of Pacific Gas and Electric Company dated as of April 21, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2004, Exhibit 3.3)
4.1	Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004, Exhibit 4)
10.1*	Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting director compensation arrangement
10.2*	Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004, adopting director compensation arrangement
10.3*	Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting amendments to the PG&E Corporation Non-Employee Director Stock Incentive Plan
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
12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
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

* Management contract or compensatory agreement.

** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

(b) The following Current Reports on Form 8-K⁽¹⁾ were filed, or furnished as indicated, during the second quarter of 2004 and through the date hereof:

1. April 7, 2004	Item 5.	Other Events and Regulation FD Disclosure
		A.  Pacific Gas and Electric Company's 2003 General Rate Case
		B.  Pacific Gas and Electric Company's Chapter 11 Proceeding
2. April 12, 2004	Item 5.	Other Events and Regulation FD Disclosure
		Pacific Gas and Electric Company's Chapter 11 Proceeding
3. April 12, 2004	Item 5.	Other Events and Regulation FD Disclosure
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 3 - Restated Articles of Incorporation of Pacific Gas and Electric Company
		Exhibit 4 - Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company
4. April 19, 2004	Item 5.	Other Events and Regulation FD Disclosure Petition for Rehearing of CPUC decisions
5. April 27, 2004	Item 5.	Other Events and Regulation FD Disclosure Pro forma financial information
6. May 4, 2004	Item 12.	Results of Operation and Financial Condition (furnished to the SEC) Release of First Quarter Earnings Results
7. May 13, 2004	Item 5.	Other Events and Regulation FD Disclosure Filing of cost of capital application
8. May 14, 2004	Item 5.	Other Events and Regulation FD Disclosure
		Pacific Gas and Electric Company's 2003 General Rate Case
9. May 14, 2004		Form 8-K/A Amendment No. 1 to Form 8-K dated May 13, 2004
	Item 5.	Other Events and Regulation FD Disclosure
10. May 25, 2004	Item 5.	Other Events and Regulation FD Disclosure
		California Public Utilities Commission (CPUC) Holding Company Conditions
11. May 28, 2004	Item 5.	Other Events and Regulation FD Disclosure
		Pacific Gas and Electric Company's 2003 General Rate Case
12. June 18, 2004	Item 5.	Other Events and Regulation FD Disclosure
		Participating Securities and the Two-Class Method of computing Earnings per Share
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 23 Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
		99.1 This exhibit is comprised of the following sections of the 2003 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Report of Independent Registered Public Accounting Firm," "Responsibility for the Consolidated Financial Statements," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Common Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," "Consolidated Statements of Shareholders' Equity," "Notes to the Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)" that have been revised to reflect the impact o f the adoption of EITF 03-06.
		99.2 Financial Statement Schedules and Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
		99.3 Computation of Earnings per Share
13. July 1, 2004	Item 5.	Other Events and Regulation FD Disclosure Loan agreements relating to issuance ofPollution Control Refunding Revenue Bonds
14. July 14, 2004	Item 5.	Other Events and Regulation FD Disclosure Pacific Gas and Electric Company's submission of long-term integrated energy resource plan
15. July 16, 2004	Item 5.	Other Events and Regulation FD Disclosure Dismissal of two CPUC commissioners' appeal of Bankruptcy Court confirmation order
16. August 3, 2004	Item 12.	Results of Operation and Financial Condition (furnished to the SEC) Release of Second Quarter Earnings Results
(1) Unless otherwise noted, all reports were filed or furnished under Commission File Number 1-12609 (PG&E Corporation) and Commission File Number 1-2348 (Pacific Gas and Electric Company).

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:  August 3, 2004

EXHIBIT INDEX

3.1	Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004, Exhibit 3)
3.2	Bylaws of PG&E Corporation dated as of April 21, 2004 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2004, Exhibit 3.2)
3.3	Bylaws of Pacific Gas and Electric Company dated as of April 21, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2004, Exhibit 3.3)
4.1	Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004, Exhibit 4)
10.1*	Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting director compensation arrangement
10.2*	Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004, adopting director compensation arrangement
10.3*	Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting amendments to the PG&E Corporation Non-Employee Director Stock Incentive Plan
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
12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
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
* Management contract or compensatory agreement.
** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.