PACIFIC GAS & ELECTRIC CO - 10-Q Quarterly Report

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

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

For the quarterly period ended September 30, 2003 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, November 10, 2003:
PG&E Corporation			414,758,513 shares
Pacific Gas and Electric Company			Wholly owned by PG&E Corporation

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company, A Debtor-In-Possession
		Condensed Consolidated Statements of Income		8
		Condensed Consolidated Balance Sheets		9
		Condensed Consolidated Statements of Cash Flows		11
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		General	12
	NOTE 2:		Utility Chapter 11 Filing	20
	NOTE 3:		Debt	26
	NOTE 4:		Discontinued Operations	28
	NOTE 5:		Price Risk Management	31
	NOTE 6:		Commitments and Contingencies	33
	NOTE 7:		Segment Information	46
	NOTE 8:		Employee Benefit Plans	47

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			48
	Liquidity and Financial Resources			51
	Results of Operations			58
	Cash Flows			65
	Commitments			68
	Regulatory Matters			68
	Risk Management Activities			80
	Critical Accounting Policies			85
	Accounting Pronouncements Issued But Not Yet Adopted			87
	Taxation Matters			87
	Additional Security Measures			88
	Other Long-Term Capital Expenditures			88
	Utility Customer Information System			89
	Environmental and Legal Matters			89
	Other Matters			89

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			90
ITEM 4.	CONTROLS AND PROCEDURES			90

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS			91
ITEM 2.	CHANGES IN SECURITIES AND USE OF PROCEEDS			94
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES			94
ITEM 5.	OTHER INFORMATION			96
ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K			97

SIGNATURES				100

PART I. FINANCIAL INFORMATION
ITEM 1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
						(Unaudited)

(in millions, except per share amounts)						Three months ended					Nine months ended
						September 30,					September 30,

						2003		2002			2003		2002

Operating Revenues
		Electric				$	2,524	$		2,483	$	5,823	$	6,454
		Natural gas				579		464			2,074		1,654

				Total operating revenues		3,103		2,947			7,897		8,108

Operating Expenses
		Cost of electricity				679		550			1,725		874
		Cost of natural gas				233		108			1,010		586
		Operating and maintenance				690		865			2,110		2,280
		Depreciation, amortization, and decommissioning				312		314			910		881
		Reorganization professional fees and expenses				16		41			116		75

				Total operating expenses		1,930		1,878			5,871		4,696

Operating Income						1,173		1,069			2,026		3,412
		Reorganization interest income				9		17			36		58
		Interest income				6		3			13		2
		Interest expense				(342)		(371)			(857)		(971)
		Other income (expense), net				(5)		60			(10)		59

Income Before Income Taxes						841		778			1,208		2,560
		Income tax provision				333		299			454		1,028

Income From Continuing Operations						508		479			754		1,532
Discontinued Operations
	Gain/(Loss) from operations of NEGT, Inc.
			(net of income tax benefit of $10 million and $85 million for the three months ended September 30, 2003, and 2002, and $230 million and $257 million for the nine months ended September 30, 2003, and 2002)
						2		(13)			(365)		(156)

Net Income Before Cumulative Effect of Changes
	in Accounting Principles					510		466			389		1,376
	Cumulative effect of changes in accounting principles, $(8) million and $(103) million related to discontinued operations for the nine months ended September 30, 2003 and 2002 (net of income tax benefit of $4 million and $42 million for the nine months ended September 30, 2003, and 2002)				-			-			(6)		(61)

Net Income						$	510	$	466		$	383	$	1,315



Weighted Average Common Shares Outstanding, Basic						387		373			384		368

Earnings Per Common Share
	from Continuing Operations, Basic					$	1.31	$	1.28		$	1.96	$	4.16



Net Earnings Per Common Share, Basic						$	1.32	$	1.25		$	1.00	$	3.57



Earnings Per Common Share
	from Continuing Operations, Diluted					$	1.24	$	1.22		$	1.86	$	4.06



Net Earnings Per Common Share, Diluted						$	1.24	$	1.19		$	0.96	$	3.49




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS


					Balance at

(in millions)					September 30,		December 31,
					2003 (Unaudited)		2002

ASSETS
Current Assets
	Cash and cash equivalents				$	4,675	$	3,532
	Restricted cash				555		527
	Accounts receivable:
			Customers (net of allowance for doubtful accounts of
				$60 million in 2003 and $59 million in 2002)	1,837		1,900
			Related parties		16		-
			Regulatory balancing accounts		196		98
	Inventories:
			Gas stored underground and fuel oil		251		154
			Materials and supplies		120		121
	Current assets of NEGT, Inc.				-		3,029
	Prepaid expenses and other				70		111

		Total current assets			7,720		9,472

Property, Plant and Equipment
	Electric				20,173		18,922
	Gas				8,291		8,123
	Construction work in progress				370		427
	Other				20		21

		Total property, plant and equipment			28,854		27,493
	Accumulated depreciation				(12,828)		(13,528)

		Net property, plant and equipment			16,026		13,965

Other Noncurrent Assets
	Regulatory assets				2,034		2,011
	Nuclear decommissioning funds				1,416		1,335
	Long-term assets of NEGT, Inc.				-		4,883
	Other				564		1,373

		Total other noncurrent assets			4,014		9,602

TOTAL ASSETS					$	27,760	$	33,039




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
			Balance at

(in millions, except per share amounts)			September 30,				December 31,
			2003 (Unaudited)				2002

LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
	Long-term debt, classified as current		$			310	$	281
	Current portion of rate reduction bonds		290				290
	Accounts payable:
		Trade creditors	479				380
		Regulatory balancing accounts	61				360
		Other	416				421
	Interest payable		216				139
	Income taxes payable		600				83
	Current liabilities of NEGT, Inc.		-				6,657
	Other		707				658

		Total current liabilities	3,079				9,269

Noncurrent Liabilities
	Long-term debt		3,313				3,715
	Rate reduction bonds		947				1,160
	Regulatory liabilities		1,074				1,461
	Asset retirement obligations		1,197				-
	Deferred income taxes		941				782
	Deferred tax credits		131				144
	Net investment in NEGT, Inc.		1,215				-
	Long-term liabilities of NEGT, Inc.		-				1,907
	Preferred stock of subsidiary with mandatory redemption provisions		137				-
	Other		2,057				1,323

		Total noncurrent liabilities	11,012				10,492

Liabilities Subject to Compromise
	Financing debt		5,604				5,605
	Trade creditors		3,713				3,580

		Total liabilities subject to compromise	9,317				9,185

Commitments and Contingencies (Notes 1, 2, 4, and 6)			-				-

Preferred Stock of Subsidiaries			285				480
Common Shareholders' Equity
	Common stock, no par value, authorized 800,000,000 shares, issued
		412,147,679 common and 1,577,770 restricted shares in 2003 and 405,486,015 common shares in 2002		6,411			6,274
	Common stock held by subsidiary, at cost, 23,815,500 shares		(690)				(690)
	Unearned compensation		(22)				-
	Accumulated deficit		(1,495)				(1,878)
	Accumulated other comprehensive loss		(137)				(93)

		Total common shareholders' equity	4,067				3,613

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$		27,760		$	33,039




See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

					(Unaudited)

					Nine months ended
(in millions)					September 30,

				2003			2002


Cash Flows From Operating Activities
	Net income				$	383		$	1,315
	Loss from discontinued operations				365			156
	Cumulative effect of changes in accounting principles				6			61

	Net income from continuing operations				754			1,532
	Adjustments to reconcile net income to
		net cash provided by operating activities:
			Depreciation, amortization, and decommissioning	910			881
			Deferred income taxes and tax credits, net	339			176
			Reversal of ISO accrual	-			(970)
			Other deferred charges and noncurrent liabilities	636			(188)
			Loss from retirement of long-term debt	89			153
			Gain on sale of assets	(10)			-
	Net effect of changes in operating assets and liabilities:
			Restricted cash		(28)			(131)
			Accounts receivable		(23)			233
			Inventories		(96)			29
			Accounts payable		262			139
			Income taxes payable		517			246
			Regulatory balancing accounts, net		(397)			(1)
			Other working capital		(26)			370
			Payments authorized by the Bankruptcy Court on amounts classified as Liabilities Subject to Compromise	(83)			(1,180)
	Other, net				72			(38)

Net cash provided by operating activities					2,916			1,251

Cash Flows From Investing Activities
	Capital expenditures				(1,183)			(1,156)
	Net proceeds from sale of asset				14			8
	Other, net				(24)			15

Net cash used by investing activities					(1,193)			(1,133)

Cash Flows From Financing Activities
	Long-term debt issued				582			564
	Long-term debt matured, redeemed, or repurchased				(1,067)			(1,241)
	Rate reduction bonds matured				(213)			(213)
	Common stock issued				120			190
	Other, net				(2)			-

Net cash provided by financing activities					(580)			(700)

Net change in cash and cash equivalents					1,143			(582)
Cash and cash equivalents at January 1					3,532			4,696

Cash and cash equivalents at September 30					$	4,675		$	4,114

Supplemental disclosures of cash flow information
	Cash received for:
		Reorganization interest income	$	30	$	59
	Cash paid for:
		Interest (net of amounts capitalized)		555		856
		Income taxes paid (refunded), net	(531)		541
		Reorganization professional fees and expenses	84		25
Supplemental disclosures of noncash investing and financing activities
	Transfer of liabilities and other payables subject to compromise from operating assets and liabilities		193		(97)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME

					(Unaudited)

					Three months ended				Nine months ended
(in millions)					September 30,				September 30,

					2003		2002		2003			2002


Operating Revenues
	Electric				$	2,524	$	2,483	$	5,823		$	6,454
	Natural gas				579		466		2,077			1,662

			Total operating revenues		3,103		2,949		7,900			8,116

Operating Expenses
	Cost of electricity				679		555		1,735			894
	Cost of natural gas				233		119		1,039			632
	Operating and maintenance				669		860		2,095			2,269
	Depreciation, amortization, and decommissioning				311		315		916			880
	Reorganization professional fees and expenses				16		41		116			75

			Total operating expenses		1,908		1,890		5,901			4,750

Operating Income					1,195		1,059		1,999			3,366
	Reorganization interest income				9		17		36			58
	Interest income				2		1		6			1
	Interest expense (noncontractual interest expense of $32 million and $99 million for the three and nine months ended September 30, 2003, and $34 million and $137 million for the three and nine months ended September 30, 2002)				(237)		(221)		(681)			(767)


	Other income (expense), net				3		1		10			(5)

Income Before Income Taxes					972		857		1,370			2,653
	Income tax provision				383		330		508			1,061

Income Before Cumulative Effect of a Change in Accounting Principle					589		527		862			1,592
		Cumulative effect of change in accounting principle
				(net of income tax benefit of $1 million for the nine months ended September 30, 2003)	-		-		(1)			-

Net Income					589		527		861			1,592
	Preferred dividend requirement				6		7		18			19

Income Available for Common Stock					$	583	$	520	$		843	$	1,573




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS

					Balance at

(in millions)					September 30,		December 31,
					2003 (Unaudited)		2002


ASSETS
Current Assets
		Cash and cash equivalents			$	4,195	$	3,343
		Restricted cash			194		150
		Accounts receivable:
			Customers (net of allowance for doubtful accounts of
				$60 million in 2003 and $59 million in 2002)	1,837		1,900
			Related parties		18		17
			Regulatory balancing accounts		196		98
		Inventories:
			Gas stored underground and fuel oil		251		154
			Materials and supplies		120		121
		Prepaid expenses and other			68		165

			Total current assets		6,879		5,948

Property, Plant and Equipment
	Electric				20,173		18,922
	Gas				8,291		8,123
	Construction work in progress				368		427

			Total property, plant and equipment		28,832		27,472
	Accumulated depreciation				(12,813)		(13,515)

			Net property, plant and equipment		16,019		13,957

Other Noncurrent Assets
		Regulatory assets			2,034		2,011
		Nuclear decommissioning funds			1,416		1,335
		Other			502		1,300

			Total other noncurrent assets		3,952		4,646

TOTAL ASSETS					$	26,850	$	24,551




See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS

				Balance at

(in millions, except per share amounts)				September 30,		December 31,
				2003 (Unaudited)		2002


LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
	Long-term debt, classified as current			$	310	$	281
	Current portion of rate reduction bonds			290		290
	Accounts payable:
		Trade creditors		479		380
		Related parties		206		130
		Regulatory balancing accounts		61		360
		Other		381		374
	Interest payable			200		126
	Income taxes payable			437		-
	Deferred income taxes			109		-
	Other			548		625

		Total current liabilities		3,021		2,566

Noncurrent Liabilities
	Long-term debt			2,429		2,739
	Rate reduction bonds			947		1,160
	Regulatory liabilities			1,074		1,461
	Asset retirement obligations			1,197		-
	Deferred income taxes			1,470		1,485
	Deferred tax credits			131		144
	Preferred stock with mandatory redemption provisions			137		-
	Other			1,966		1,274

		Total noncurrent liabilities		9,351		8,263

Liabilities Subject to Compromise
	Financing debt			5,604		5,605
	Trade creditors			3,897		3,786

		Total liabilities subject to compromise		9,501		9,391

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

Preferred Stock With Mandatory Redemption Provisions
	6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009				-	137
Shareholders' Equity
	Preferred stock without mandatory redemption provisions
		Nonredeemable, 5% to 6%, outstanding 5,784,825 shares	145			145
		Redeemable, 4.36% to 7.04%, outstanding 5,973,456 shares	149			149
	Common stock, $5 par value, authorized 800,000,000 shares,
		issued 321,314,760 shares	1,606			1,606
	Common stock held by subsidiary, at cost, 19,481,213 shares		(475)			(475)
	Additional paid-in capital		1,964			1,964
	Reinvested earnings		1,648			805
	Accumulated other comprehensive loss		(60)			-

		Total shareholders' equity	4,977			4,194

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$		26,850	$	24,551



See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
					(Unaudited)
						Nine months ended
(in millions)						September 30,

						2003			2002

Cash Flows From Operating Activities
	Net income					$	861		$	1,592
	Adjustments to reconcile net income to
			net cash provided by operating activities:
				Depreciation, amortization, and decommissioning		916			880
				Deferred income taxes and tax credits, net		122			157
				Other deferred charges and noncurrent liabilities		395			(141)
				Gain on sale of assets		(10)			-
				Reversal of ISO accrual		-			(970)
				Cumulative effect of changes in accounting principles		2			-
	Net effect of changes in operating assets and liabilities:
		Restricted cash				(44)		(57)
		Accounts receivable				(8)			245
		Inventories				(96)			29
		Accounts payable				350			139
		Income taxes payable				437			179
		Regulatory balancing accounts, net				(397)			(1)
		Other working capital				77			345
		Payments authorized by the Bankruptcy Court on amounts
		classified as Liabilities Subject to Compromise				(83)			(1,180)
	Other, net					17			37

Net cash provided by operating activities						2,539			1,254

Cash Flows From Investing Activities
	Capital expenditures					(1,182)			(1,156)
	Net proceeds from sale of assets					14			8
	Other, net					(25)			16

Net cash used by investing activities						(1,193)			(1,132)

Cash Flows From Financing Activities
	Long-term debt matured, redeemed, or repurchased					(280)			(333)
	Rate reduction bonds matured					(213)			(213)
	Other, net					(1)			-

Net cash used by financing activities						(494)			(546)

Net change in cash and cash equivalents						852			(424)
Cash and cash equivalents at January 1						3,343			4,341

Cash and cash equivalents at September 30						$	4,195		$	3,917



Supplemental disclosures of cash flow information
	Cash received for:
		Reorganization interest income				$	30		$	59
	Cash paid for:
		Interest (net of amounts capitalized)				475			830
		Income taxes paid (refunded), net				(32)			708
		Reorganization professional fees and expenses				84			25
Supplemental disclosures of noncash investing and financing activities
	Transfer of liabilities and other payables subject to
		compromise (to) from operating assets and liabilities, net				193			(97)

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 (Utility), a vertically integrated electricity and natural gas utility. PG&E Corporation became the holding company of the Utility, a debtor-in-possession, and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. The Utility delivers electric service to approximately 5 million customers and natural gas service to approximately 4 million customers in Northern and Central California. Both PG&E Corporation and the Utility are headquartered in San Francisco. As discussed further in Note 2, on April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (referred to as the Bankrupt cy Court in this report's discussion of the Utility's Chapter 11 filing). Pursuant to Chapter 11, the Utility has retained control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court.

PG&E Corporation's other significant subsidiary is PG&E National Energy Group, Inc. (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 (referred to as the Bankruptcy Court in this report's discussion of PG&E NEG's Chapter 11 filing). Subsequently, on July 29, 2003, two additional subsidiaries of PG&E NEG also filed voluntary Chapter 11 petitions. Pursuant to Chapter 11, PG&E NEG and those subsidiaries in bankruptcy 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 July 8, 2003, PG&E NEG also filed a proposed plan o f reorganization with the Bankruptcy Court that, if implemented, would eliminate PG&E Corporation's equity interest in PG&E NEG. On October 3, 2003, the Bankruptcy Court authorized PG&E NEG to change its name to National Energy and Gas Transmission, Inc. (NEGT, Inc.). The change reflects NEGT, Inc.'s pending separation from PG&E Corporation. Consequently, all subsequent references to PG&E NEG in these Notes to the Condensed Consolidated Financial Statements, including its Chapter 11 filing and its plan of reorganization, will refer to NEGT, Inc.

Under accounting principles generally accepted in the United States of America (GAAP), consolidation is generally required for investments of more than 50 percent 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. As discussed above, as a result of NEGT, Inc.'s Chapter 11 filing, the resignation of PG&E Corporation's representatives who previously served on the NEGT, Inc. Board of Directors, and their replacement with Board members who are not affiliated with PG&E Corporation, PG&E Corporation no longer retains significant influence over the ongoing operations of NEGT, Inc. PG&E Corporation anticipates that the Bankruptcy Court will approve NEGT, Inc.'s proposed plan of reorganization, or a plan with similar equity loss provisions for PG&E Corp oration. Therefore, as of July 8, 2003, PG&E Corporation has deconsolidated the operations of NEGT, Inc. and has reflected its ownership interest in NEGT, Inc. utilizing the cost method of accounting, under which PG&E Corporation's investment in NEGT, Inc. is reflected as a single amount on the Condensed Consolidated Balance Sheet of PG&E Corporation, and the recording of earnings and losses from NEGT, Inc. ceased after July 7, 2003. In addition, for the reasons described above, PG&E Corporation considers NEGT, Inc. to be an abandoned asset under Statement of Financial Accounting Standards (SFAS), "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS No. 144), and, as a result, the operations of NEGT, Inc. prior to July 8, 2003, are reflected as discontinued operations on the Condensed 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 Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility's Consolidated Financial Statements include its accounts and those of its wholly owned and controlled subsidiaries. Both PG&E Corporation's and the Utility's Consolidated Balance Sheets as of December 31, 2002, were derived from the audited Consolidated Balance Sheets, filed in the combined 2002 Annual Report on Form 10-K, as amended.

PG&E Corporation and the Utility believe that the accompanying Consolidated Financial Statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q. All significant intercompany transactions have been eliminated from the Consolidated Financial Statements.

This Quarterly Report should be read in conjunction with PG&E Corporation's and the Utility's Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in their combined 2002 Annual Report on Form 10-K, as amended, and PG&E Corporation's and the Utility's other reports filed with the Securities and Exchange Commission (SEC) since their combined 2002 Annual Report on Form 10-K, as amended, was filed.

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. 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 have been prepared in accordance with the American Institute of Certified Public Accountants' Statement of Position (SOP) 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code" (SOP 90-7), and on a going-concern basis, which contemplates continuity of operation, realization of assets, and liquidation of liabilities in the ordinary course of business. As a result of the Utility's Chapter 11 filing, the realization of assets and liquidation of liabilities are subject to uncertainty. Under SOP 90-7, certain claims against the Utility existing before the Utility's Chapter 11 filing are 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 are reported separately as reorganization items. Finally, the extent to which the Utility's reported interest expense differs from its stated contractual interest is disclosed on the Utility's Consolidated Statements of Income.

Certain amounts in the 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation. These reclassifications did not affect the consolidated net income reported by PG&E Corporation and the Utility for the periods presented.

Adoption of New Accounting Policies and Summary of Significant Accounting Policies

The accounting policies used by PG&E Corporation and the Utility include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). Except as disclosed below, PG&E Corporation and the Utility are following the same accounting policies discussed in their combined 2002 Annual Report on Form 10-K, as amended.

Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity

In May 2003, the Financial Accounting Standards Board (FASB) issued Statement No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). SFAS No. 150 addresses concerns of how to measure and classify in the balance sheet certain financial instruments that have characteristics of both liabilities and equity. The following freestanding financial instruments must be classified as liabilities: mandatorily redeemable financial instruments, obligations to repurchase an issuer's equity shares by transferring assets, and certain obligations to issue a variable number of shares.

PG&E Corporation and the Utility adopted the requirements of SFAS No. 150 in the third quarter of 2003. As a result, the Utility reclassified and remeasured $137 million of preferred stock with mandatory redemption provisions as a noncurrent liability. The remeasurement and reclassification did not have an impact on earnings of PG&E Corporation or the Utility. Upon adopting SFAS No. 150 all amounts paid or to be paid to the holders of preferred stock with mandatory redemption provisions in excess of the initial measured amount are reflected in interest cost. Dividends paid or accrued in prior periods have not been reclassified.

Determining Whether an Arrangement Contains a Lease

In May 2003, the Emerging Issues Task Force (EITF) reached consensus on EITF 01-8, "Determining Whether an Arrangement Contains a Lease" (EITF 01-8). EITF 01-8 establishes criteria to be applied to any new or modified agreement in order to ascertain if such agreement is in effect a lease, and subject to lease accounting treatment and disclosure requirements principally found in SFAS No. 13, "Accounting for Leases" (SFAS No. 13). EITF 01-8 is effective for all new or modified arrangements entered into as of July 1, 2003. The adoption of EITF 01-8 did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

Amendment of Statement 133 on Derivative Instruments and Hedging Activities

In April 2003, the FASB issued Statement No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies circumstances under which a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. The provisions of SFAS No. 149 that relate to SFAS No. 133 Implementation Issues that have been effective for periods that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates.

The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

Guarantor's Accounting and Disclosure Requirements for Guarantees

PG&E Corporation incorporated the disclosure requirements from FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45), into its December 31, 2002, disclosures of guarantees. Beginning January 1, 2003, PG&E Corporation applied the initial recognition and measurement provisions of FIN 45 to guarantees issued or modified after December 31, 2002.

FIN 45 elaborates on existing disclosure requirements for most guarantees. It also clarifies that at the time a company issues a guarantee, it must recognize a liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that specified triggering events or conditions occur. This information also must be disclosed in interim and annual financial statements.

The adoption of this interpretation did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

Accounting for Asset Retirement Obligations

On January 1, 2003, PG&E Corporation adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143). SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible long-lived assets. SFAS No. 143 requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred, if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and costs recovered through the ratemaking process.

The impacts of adopting SFAS No. 143 were as follows:

The Utility has identified its nuclear generation and certain fossil generation facilities as having asset retirement obligations as of January 1, 2003. No additional asset retirement obligations had been identified as of September 30, 2003. Through December 31, 2002, the Utility had recorded $1.4 billion for its nuclear and fossil decommissioning obligations in Accumulated Depreciation and Decommissioning in the Consolidated Balance Sheets.

Upon adoption of SFAS No. 143, the Utility reclassified the decommissioning liabilities recorded through December 31, 2002 as Asset Retirement Obligations in the Consolidated Balance Sheets. To record the decommissioning liabilities at fair value as required by SFAS No. 143, the Utility then reduced the asset retirement obligations by $53 million. The Utility increased its Property, Plant and Equipment balance by $332 million to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, less accumulated depreciation from the date the obligation was incurred through December 31, 2002. Finally, the Utility recorded a regulatory liability of $387 million to reflect the cumulative effect of adoption for its nuclear facilities. This regulatory liability represents timing differences between recognition of nuclear decommissioning obligations in accordance with GAAP and ratemaking purposes. The cumulative effect of the change in accounting principle for the Utility's fo ssil facilities as a result of adopting SFAS No. 143 was a loss of $1 million, after-tax.

In connection with an application filed with the CPUC requesting an increase in the Utility's nuclear decommissioning revenue requirements for the years 2003 through 2005, the Utility developed a new estimate for costs to decommission its nuclear facilities. As a result, the Utility has reduced its asset retirement obligation by $223 million from the amount recorded upon the Utility's adoption of SFAS No. 143 on January 1, 2003. The Utility also reduced its Property, Plant and Equipment balance by $61 million. Finally, to account for timing differences between recognition of the modified asset retirement obligation as recorded in accordance with GAAP and ratemaking purposes, the Utility increased its regulatory liability by $162 million.

If SFAS No. 143 had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the three- and nine-month periods ended September 30, 2002 would not have been material. The amounts recorded upon adoption of SFAS No. 143 reflect the pro forma effects on the Consolidated Balance Sheets if SFAS No. 143 had been adopted on December 31, 2002.

The Utility has established trust funds that are legally restricted for purposes of settling its nuclear decommissioning obligations. As of September 30, 2003, the fair value of these trust funds was approximately $1.4 billion.

The Utility may have potential asset retirement obligations under various land right documents associated with its transmission and distribution facilities. The majority of the Utility's land rights are perpetual. Any non-perpetual land rights generally are renewed continuously because the Utility intends to utilize these facilities indefinitely. Since the timing and extent of any potential asset retirements are unknown, the fair value of any obligations associated with these facilities cannot be reasonably estimated.

The Utility collects estimated removal costs in rates through depreciation in accordance with regulatory treatment. These amounts do not represent SFAS No. 143 asset retirement obligations and will continue to be recorded in accumulated depreciation. As of September 30, 2003, the Utility's estimated removal costs recorded in accumulated depreciation were approximately $1.8 billion.

Accounting for Costs Associated with Exit or Disposal Activities

On January 1, 2003, PG&E Corporation adopted SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity" (EITF 94-3). SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF 94-3, a liability for an exit cost is recognized at the commitment date of an exit plan. SFAS No. 146 also establishes that the liability initially should be measured and recorded at fair value. The adoption of SFAS No. 146 did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility at the date of adoption.

Earnings Per Share

Basic earnings per share is calculated by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income, adjusted for the net interest and amortization associated with PG&E Corporation's Convertible Subordinated Notes, by the sum of the weighted average number of common shares outstanding and the assumed issuance of common shares for all dilutive securities.

The following is a reconciliation of PG&E Corporation's net income and weighted average common shares outstanding for calculating basic and diluted net income per share:

			Three months ended				Nine months ended
(in millions, except per share amounts)			September 30,				September 30,

			2003		2002		2003		2002


Income from continuing operations			$	508	$	479	$	754	$	1,532
Discontinued operations				2		(13)		(365)		(156)

Net income before cumulative effect of changes
	in accounting principles		510		466		389		1,376
Cumulative effect of changes in accounting principles			-		-		(6)		(61)

Net Income			510		466		383		1,315
Interest expense on 9.5% Convertible Subordinated Notes			4		3		12		4

Net Income for Diluted Calculations			$	514	$	469	$	395	$	1,319




Weighted average common shares outstanding, basic			387		373		384		368
Add:		Employee stock options and PG&E Corporation
		shares held by grantor trusts	5		-		2		2
		PG&E Corporation Warrants	5		3		5		1
		9.5% Convertible Subordinated Notes	19		19		19		7

Shares outstanding for diluted calculations			416		395		410		378



Earnings Per Common Share, Basic
Income from continuing operations			$	1.31	$	1.28	$	1.96	$	4.16
Discontinued operations			0.01		(0.03)		(0.95)		(0.42)
Cumulative effect of changes in accounting principles			-		-		(0.01)		(0.17)

Net earnings			$	1.32	$	1.25	$	1.00	$	3.57



Earnings Per Common Share, Diluted
Income from continuing operations			$	1.24	$	1.22	$	1.86	$	4.06
Discontinued operations			-		(0.03)		(0.89)		(0.41)
Cumulative effect of changes in accounting principles			-		-		(0.01)		(0.16)

Net earnings			$	1.24	$	1.19	$	0.96	$	3.49

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" (SFAS No. 123), as amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure, an Amendment of FASB Statement No. 123" (collectively, SFAS No. 123). 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. Had compensation expense been recognized using the fair value-based method under SFAS No. 123, PG&E Corporation's pro forma consolidated earnings and earnings per share would have been as follows:

			Three months ended				Nine months ended
(in millions, except per share amounts)			September 30,				September 30,

			2003		2002		2003		2002

Net income:
As reported			$	510	$	466	$	383	$	1,315
	Deduct: Total stock-based employee
		compensation expense determined
		under the fair value based method
		for all awards, net of related tax effects		5		5		15		14

Pro forma			$	505	$	461	$	368	$	1,301




Basic earnings per share:
As reported				1.32		1.25		1.00		3.57
Pro forma				1.30		1.24		0.96		3.54

Diluted earnings per share:
As reported				1.24		1.19		0.96		3.49
Pro forma				1.22		1.17		0.93		3.45

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

			Three months ended				Nine months ended
(in millions)			September 30,				September 30,

			2003		2002		2003		2002

Income available for common stock:
As reported			$	583	$	520	$	843	$	1,573
	Deduct: Total stock-based employee
		compensation expense determined
		under the fair value based method
		for all awards, net of related tax effects		2		2		6		5

Pro forma			$	581	$	518	$	837	$	1,568

As of September 30, 2003, a total of 1.6 million shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries. The shares were granted with restrictions and are subject to forfeiture unless certain conditions are met.

The restricted shares were issued at the grant date and are held in an escrow account. The shares become available to the employees as the restrictions lapse. In general, the restrictions on 80 percent of the shares lapse automatically over a period of four years at the rate of 20 percent per year. The compensation expense for these shares remains fixed at the value of the stock at grant date. Restrictions on the remaining 20 percent of the shares will lapse at a rate of 5 percent 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.

Compensation expense associated with all the shares is recognized on a quarterly basis, by amortizing the unearned compensation related to that period. Total compensation expense resulting from the restricted stock issuance reflected on PG&E Corporation's Consolidated Statements of Income was $1.8 million and $5.0 million for the three- and nine-month periods ended September 30, 2003, of which $1.0 million and $2.9 million for the three- and nine-month periods was recognized by the Utility.

The total unamortized balance of unearned compensation resulting from the restricted stock issuance reflected on PG&E Corporation's Consolidated Balance Sheets was $22 million at September 30, 2003.

Comprehensive Income

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

			Three months ended				Nine months ended
			September 30, 2003				September 30, 2003

			PG&E				PG&E
			Corporation ⁽¹⁾		Utility		Corporation ⁽¹⁾		Utility

Net income available for common stock			$	510	$	583	$	383	$	843
Continuing operations
	Foreign currency translation adjustment		-		-		3		-
	Retirement plan remeasurement (Note 8)		-		-		(60)		(60)

	Comprehensive income from continuing operations		510		583		326		783
Discontinued operations (Note 4)
	Net loss in other comprehensive income (OCI)
		from current period hedging transactions and price
		changes in accordance with SFAS No. 133	-		-		(5)		-
	Net reclassification from OCI to earnings		2		-		17		-
	Other		1		-		1		-

	Comprehensive income from discontinued operations		3		-		13		-

Total comprehensive income			$	513	$	-	$	339	$	783




⁽¹⁾	Includes other comprehensive income of NEGT, Inc. prior to July 8, 2003, after which PG&E Corporation accounts for NEGT, Inc. using the cost method of accounting.

		Three months ended				Nine months ended
		September 30, 2002				September 30, 2002

		PG&E				PG&E
		Corporation		Utility		Corporation		Utility

Net income available for common stock		$	466	$	520	$	1,315	$	1,573
Net loss in other comprehensive income (OCI)
	from current period hedging transactions and price
	changes in accordance with SFAS No. 133	(153)		-		(237)		-
Net reclassification from OCI to earnings		(2)		-		3		-
Foreign currency translation adjustment		-		-		3		2

Total comprehensive income		$	311	$	520	$	1,084	$	1,575

The above changes to OCI are stated net of income taxes benefits of zero and $46 million for the three- and nine-month periods ended September 30, 2003, and $91 million and $132 million for the three- and nine-month periods ended September 30, 2002.

Income Taxes

In 2003, PG&E Corporation increased its valuation allowance due to the uncertainty in realizing certain state deferred tax assets arising at NEGT, Inc. Valuation allowances of zero and $24 million were recorded in discontinued operations, and zero and $5 million in accumulated other comprehensive loss for the three- and nine-month periods ended September 30, 2003.

In addition, PG&E Corporation recognized federal deferred tax assets related to losses incurred at NEGT, Inc. These deferred tax assets were determined on a consolidated basis, with the related tax benefit of zero and $157 million recorded in discontinued operations, zero and $3 million recorded in cumulative effect of changes in accounting principles, and zero and $44 million in accumulated other comprehensive loss for the three- and nine-month periods ended September 30, 2003.

Upon deconsolidation of NEGT, Inc. for financial statement purposes, PG&E Corporation adopted the cost method of accounting for its ownership interest in NEGT, Inc. As a result of this accounting change, PG&E Corporation will not recognize additional deferred tax assets after July 8, 2003, with respect to losses of NEGT, Inc. even though it continues to include NEGT, Inc. and its subsidiaries in its consolidated income tax returns. Any unrealized deferred tax assets relating to the losses of NEGT, Inc. that have been recognized through July 7, 2003, will reverse at the time that PG&E Corporation releases its ownership interest in NEGT, Inc. This reversal of deferred tax assets will partially offset any one-time gain recognized when PG&E Corporation writes off its net investment in NEGT, Inc.

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. 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 (GTNW), formerly known as PG&E Gas Transmission, Northwest Corporation. Effective April 1, 2003, the Utility no longer purchases nat ural gas from NEGT Energy Trading Holdings Corporation (NEGT ET), formerly known as PG&E Energy Trading Holdings Corporation. Both GTNW and NEGT ET are subsidiaries of NEGT, Inc. The Utility continues to sell natural gas transmission capacity and other ancillary services to NEGT ET. These services are priced at either tariff rates or fair market value, depending on the nature of the services provided. Intercompany transactions are eliminated in consolidation; therefore, no profit results from these transactions. The Utility's significant related party transactions and related receivable (payable) balances were as follows:

	Three months ended September 30,				Nine months ended September 30,				Receivable (Payable) Balance Outstanding at
(in millions)									September 30,		December 31,

	2003		2002		2003		2002		2003		2002

Utility revenues from:
Administrative services provided to PG&E Corporation	$	2	$	3	$	6	$	6	$	1	$	1
Natural gas transmission capacity services provided to NEGT ET	2		2		6		8		1		-
Contribution in aid of construction received from NEGT, Inc.	-		-		-		-		-		3
Trade deposit due from GTNW	-		-		3		-		15		12
Utility expenses from:
Administrative services received from PG&E Corporation	$	40	$	16	$	137	$	66	$	(376)	$	(289)
Interest accrued on pre-petition liability due to PG&E Corporation	2		-		5		-		(2)		(2)
Administrative services received from NEGT, Inc.	-		-		2		-		(1)		(2)
Software purchases from NEGT ET	-		-		1		-		-		-
Gas commodity services received from NEGT ET	-		5		10		33		-		(26)
Gas transportation services received from GTNW	14		11		43		33		(8)		(8)
Trade deposit due to NEGT ET	(6)		-		(5)		-		(2)		(7)

Payment of outstanding amounts owed to the Utility by NEGT, Inc. as of July 8, 2003, the date of NEGT, Inc.'s Chapter 11 filing, are subject to the approval of the Bankruptcy Court.

Accounting Pronouncements Issued But Not Yet Adopted
Consolidation of Variable Interest Entities

In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46), which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity. A "variable interest entity" is an entity that does not have sufficient equity investment at risk or lacks the essential characteristics of a controlling financial interest.

Until the issuance of FIN 46, a company generally included another entity in its consolidated financial statements only if it controlled the entity through voting interests. FIN 46 changes that by requiring a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity's activities or is entitled to receive a majority of the entity's residual returns, or both. A company that consolidates a variable interest entity is now referred to as the "primary beneficiary" of that entity. FIN 46 requires disclosure of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.

The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by PG&E Corporation or the Utility between February 1, 2003 and September 30, 2003. PG&E Corporation and the Utility must apply the provisions of FIN 46 as of December 31, 2003, for entities created prior to February 1, 2003.

PG&E Corporation and the Utility are continuing to evaluate the impacts of FIN 46's initial recognition, measurement, and disclosure provisions on the consolidated financial statements and are unable to estimate the impact, if any, which will result when FIN 46 becomes effective. The Utility has investments in unconsolidated affiliates, which are mainly engaged in the purchase of residential real estate property. It is reasonably possible that the Utility will be required to consolidate its interests in two of these entities as a result of the adoption of FIN 46. As of September 30, 2003, the Utility's recorded investment in these entities is approximately $17 million. As a limited partner, the Utility's exposure to potential loss is limited to its investment in each partnership.

Changes to Accounting for Certain Derivative Contracts

In June 2003, the FASB issued a new Derivatives Implementation Group (DIG) interpretation of SFAS No. 133, Issue No. C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature" (DIG C20). DIG C20 specifies additional circumstances under which price adjustment features, such as those based on broad market indices, in a derivative contract would not be an impediment to qualify for the normal purchases and normal sales scope exception under SFAS No. 133. One of the attributes necessary to qualify for the normal purchases and sales exception is that the pricing must be deemed to be clearly and closely related to the asset to be delivered under the contract. Under DIG C20, as long as the price adjustment feature in a contract is expected to be highly correlated to the asset to be delivered under that contract, the use of a broad market index (such as the consumer price index) as a price a djustment feature is considered clearly and closely related. Previously, under DIG C11, "Interpretations of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exceptions," the use of a price adjustment based on a broad market index was not considered to be clearly and closely related to the asset to be delivered, and the contract was not eligible for the normal purchases and sales exception. The guidance in DIG C11 is superseded by DIG C20.

The implementation guidance in DIG C20 is effective for derivative contracts in the fourth quarter of 2003. Application of the DIG C20 guidance to existing contracts that were not previously eligible for the normal purchases and sales exception under DIG C11 will be applied prospectively. The contract's fair value as of the date of adoption of DIG C20 should become the carrying value at that date. PG&E Corporation and the Utility currently are evaluating the impacts, if any, of DIG C20 on their Consolidated Financial Statements.

NOTE 2: UTILITY 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 2002 Annual Report on Form 10-K, as amended.

Chapter 11 Filing

On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court for the Northern District of California. Pursuant to Chapter 11, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while subject to the jurisdiction of the Bankruptcy Court. PG&E Corporation and subsidiaries of the Utility, including PG&E Funding LLC (which issued rate reduction bonds) and PG&E Holdings, LLC (which holds stock of the Utility), are not included in the Utility's Chapter 11 filing.

In connection with the Utility's Chapter 11 proceeding, various parties filed claims with the Bankruptcy Court totaling approximately $51.3 billion. Of these claims filed, $9.9 billion is related to California Independent System Operator (ISO)/Power Exchange (PX) and generator claims. Pursuant to the Bankruptcy Court's Order on Debtor's Omnibus Objection to Duplicate PX and Generator Claims, the aggregate allowable amount of these claims is limited to approximately $1.8 billion. Of that amount, approximately $0.2 billion is subject to a pre-petition offset, thereby reducing the aggregate allowable amount to approximately $1.6 billion. The Utility expects that this $1.6 billion amount will be further reduced as a result of certain proceedings pending at the FERC. Of the remaining $43.0 billion of filed claims, approximately $23.4 billion has been disallowed by the Bankruptcy Court due to objections, claim withdrawals, and agreements with claimants. The Utility has objected to, or intends to object to , approximately $0.9 billion of the remaining $19.6 billion of filed claims. In addition, of the remaining approximately $19.6 billion of filed claims, approximately $5.5 billion of such claims are expected to pass through the Chapter 11 proceeding and be determined in a forum other than the Bankruptcy Court, or do not represent liabilities for which payment will be required by the Utility. Since the Utility's filing for Chapter 11 protection in April 2001, the Utility has made approximately $2.0 billion in claim-related principal payments.

The Utility has recorded its estimate of all valid claims at September 30, 2003, as $9.5 billion of Liabilities Subject to Compromise, which includes interest on disputed claims, and $2.7 billion of Long-Term Debt. As of December 31, 2002, the Utility had recorded $9.4 billion of Liabilities Subject to Compromise. The increase from $9.4 billion is primarily due to interest accruals during the nine months ended September 30, 2003.

The Bankruptcy Court has authorized certain payments and actions necessary for the Utility to continue its normal business operations while operating as a debtor-in-possession. For example, the Utility is authorized to pay employee wages and benefits, amounts due under contracts with the majority of qualifying facilities (QFs), interest on certain secured and unsecured debt, environmental remediation expenses, and expenditures related to property, plant and equipment. In addition, the Utility is authorized to refund certain customer deposits, use certain bank accounts and make cash collateral deposits, and assume responsibility for various hydroelectric contracts. The Utility also has received permission from the Bankruptcy Court to make payments on (1) pre- and post-petition interest on certain claims, (2) pre-petition secured debt that has matured, and (3) certain other claims.

The Utility has agreed to pay pre- and post-petition interest on Liabilities Subject to Compromise at the rates set forth below.

(in millions)

Amount Owed

Agreed Upon Interest Rate
at September 30, 2003
(per annum)

Commercial Paper Claims

$

873

8.216%

Floating Rate Notes

1,240

8.333%

Senior Notes

680

10.375%

Medium-Term Notes

287

6.560% to 9.200%

Revolving Line of Credit Claims

938

8.750%

Pollution Control Bonds

814

1.230% to 5.350%

QFs

52

5.000%

Other Claims

4,617

3.100% to 12.000%

Liabilities Subject to Compromise at September 30, 2003

$

  9,501

As the Utility's proposed plan of reorganization (see below) did not become effective on or before September 15, 2003, the interest rates for Commercial Paper Claims, Floating Rate Notes, Senior Notes, Medium-Term Notes, and Revolving Line of Credit Claims set forth above reflect an increase of a total of 75.0 basis points over the originally agreed upon rates, for periods on and after September 15, 2003. If the effective date of the proposed plan of reorganization does not occur on or before March 15, 2004, the interest rates for these claims on and after such date will increase by an additional 37.5 basis points. For other claims, the Utility has recorded interest at the contractual or FERC-tariffed interest rate. When those rates do not apply, the Utility has recorded interest at the federal judgment rate.

Competing Plans of Reorganization

In September 2001, PG&E Corporation and the Utility submitted a proposed plan of reorganization to the Bankruptcy Court (the original plan of reorganization) that proposed to disaggregate the Utility's current business and to refinance the restructured businesses. In April 2002, the CPUC, later joined by the Official Committee of Unsecured Creditors (OCC), submitted an alternate proposed plan of reorganization with the Bankruptcy Court that did not provide for disaggregation of the Utility's business. In March 2003, the Bankruptcy Court stayed all proceedings relating to the confirmation trial for the competing plans to allow the Utility, the CPUC, and certain other parties to participate in a judicially supervised settlement conference in order to explore the possibility of resolving the differences between the competing plans of reorganization and developing a consensual plan.

The Proposed CPUC Settlement Agreement

On June 19, 2003, PG&E Corporation, the Utility, and the staff of the CPUC announced a proposed settlement agreement that contemplates a new plan of reorganization (Settlement Plan) to supersede the competing plans of reorganization. Under the proposed CPUC settlement agreement, PG&E Corporation and the Utility would agree that the Utility remains a vertically integrated utility subject to the CPUC's jurisdiction. The proposed CPUC settlement agreement would permit the Utility to emerge from Chapter 11 as an investment grade rated company (at least BBB- from Standard & Poor's (S&P) and Baa3 from Moody's Investors Service (Moody's)), and to pay in full all the Utility's valid creditor claims, plus applicable interest.

The proposed CPUC settlement agreement contains a statement of intent that it is in the public interest to restore the Utility to financial health and to maintain and improve the Utility's financial condition in the future to ensure that the Utility is able to provide safe and reliable electricity and natural gas service to its customers at just and reasonable rates. In addition, the proposed CPUC settlement agreement includes a statement of intent that it is fair and in the public interest to allow the Utility to recover prior uncollected costs over a reasonable time and to provide the opportunity for shareholders to earn a reasonable rate of return on the Utility's business. Under the proposed CPUC settlement agreement, the Utility would release claims against the CPUC that the Utility or PG&E Corporation would have retained under the original plan of reorganization.

The Utility currently expects to have approximately $9.4 billion in total debt outstanding (excluding the rate reduction bonds) on the effective date of the Settlement Plan. The actual amount of debt that the Utility would issue will depend upon how certain claims are resolved and the amount of cash on hand at the time the Settlement Plan becomes effective, as well as cash requirements related to closing out any interest rate hedges and whether all intended reinstated debt will be reinstated.

The proposed CPUC settlement agreement is subject to the approval of the Boards of Directors of PG&E Corporation and the Utility, as well as the CPUC. In addition, the proposed CPUC settlement agreement must be executed by all parties on or before December 31, 2003. The CPUC currently is expected to vote on the settlement agreement in late December 2003.

In addition, the Bankruptcy Court must confirm the Settlement Plan. While the CPUC is not a proponent, it would agree under the proposed CPUC settlement agreement to support the Settlement Plan. On July 31, 2003, the Bankruptcy Court approved the disclosure statement that was used to solicit approval of the Settlement Plan from creditors entitled to vote on the Settlement Plan. Solicitation of creditor votes ended on September 29, 2003. On October 14, 2003, the Utility filed the voting results with the Bankruptcy Court. All of the creditor classes that voted on the Settlement Plan voted in favor of the Settlement Plan. The confirmation hearing began on November 10, 2003.

The principal terms of the proposed CPUC settlement agreement are as follows:

Regulatory Asset

The CPUC would agree to establish a $2.2 billion after-tax regulatory asset (Regulatory Asset), which equates to an approximately $3.7 billion pre-tax regulatory asset, as a new, separate and additional part of the Utility's rate base that would be amortized on a ''mortgage-style'' basis over nine years beginning January 1, 2004. The Regulatory Asset would be fully amortized by the end of 2012. The CPUC also would agree to authorize the Utility to establish a tax tracking account, to be used if the Utility must pay income tax on the Regulatory Asset before it is fully amortized, to record the difference between taxes on the Regulatory Asset plus interest imposed by federal or state tax authorities for earlier recognition and taxes that would have been incurred on account of the Regulatory Asset had it been taxed during the amortization period. The tax tracking account will earn the authorized rate of return and be amortized into rates over the longer of the remaining life of the Regulatory Asset or fi ve years.

The net after-tax amount of any refunds, claim offsets, or other credits from generators or other energy suppliers relating to the Utility's PX, ISO, QF, or energy service provider costs during the California energy crisis that the Utility realizes in cash or by offset of creditor claims in its Chapter 11 case will reduce the outstanding balance of the Regulatory Asset, dollar for dollar. Similarly, the net after-tax amounts received in cash by the Utility for electricity claims under the master settlement agreement with El Paso Corporation and certain of its affiliates also would cause a reduction in the outstanding balance and the remaining amortization of the Regulatory Asset.

The Regulatory Asset would earn a return on equity (ROE) of at least 11.22 percent annually for its term and, after the equity component of the Utility's capital structure reaches 52.00 percent, the authorized equity component of the Regulatory Asset would be no less than 52.00 percent for the remaining term of the Regulatory Asset. The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

Ratemaking Matters

The CPUC would agree that the Utility's rate base for its utility retained generation would be deemed just and reasonable and would not be subject to modification, adjustment, or reduction, except as necessary to reflect capital expenditures and any change in authorized depreciation. This would result in the recording of an additional after-tax regulatory asset of approximately $0.8 billion (or approximately $1.3 billion pre-tax). The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

The CPUC would timely act upon the Utility's applications to collect in rates prudently incurred costs (including return of and return on) of any new and reasonable investment in utility plant and assets. The CPUC also would promptly adjust the Utility's rates consistent with the California legislation (Assembly Bill (AB) 57 and Senate Bill (SB) 1976) and the CPUC's 2002 agreement with the California Department of Water Resources (DWR) regarding the establishment of the DWR's revenue requirements to ensure that the Utility's collection of certain charges to service existing rate reduction bonds, regulatory asset amortization and return, and base revenue requirements (e.g., electricity and natural gas distribution, the Utility's rate base for its electricity generation, gas commodity procurement, existing QF contract costs, and associated return) are not impaired. The CPUC would not discriminate against the Utility because of the Utility's Chapter 11 case, the Utility's pending federal lawsuit against t he CPUC Commissioners to recover its previously incurred costs of providing electric service from ratepayers under the federal filed rate doctrine, the proposed CPUC settlement agreement, the Regulatory Asset, or any other matters addressed in or resolved by the proposed CPUC settlement agreement.

The CPUC would maintain the Utility's retail electric rates at current levels through December 31, 2003. As of January 1, 2004, the CPUC may adjust the Utility's retail electric rates prospectively consistent with the proposed CPUC settlement agreement, the Settlement Plan, the order confirming the Settlement Plan, and California law. The proposed CPUC settlement agreement includes a statement of intent that under the Settlement Plan, retail electricity rates would be reduced in January 2004, with further reductions expected thereafter.

The CPUC would set the Utility's capital structure and authorized ROE in the Utility's annual cost of capital proceedings in its usual manner. However, from January 1, 2004, until S&P has issued a long-term issuer credit rating for the Utility of at least A- or Moody's has issued an issuer credit rating for the Utility of at least A3, the authorized ROE would be no less than 11.22 percent per year and the authorized equity ratio for ratemaking purposes would be no less than 52.00 percent, except that for 2004 and 2005, the authorized equity ratio would equal the greater of the proportion of equity in the forecast of its average capital structure for calendar years 2004 and 2005 filed in the Utility's cost of capital proceeding and 48.60 percent.

The CPUC also would agree to act promptly on certain of the Utility's pending ratemaking proceedings, including the Utility's pending 2003 General Rate Case (GRC). The outcome of these proceedings may result in the establishment of additional regulatory assets on the Utility's Consolidated Balance Sheets.

California Department of Water Resources Contracts

The Utility would agree to accept an assignment of, or to assume legal and financial responsibility for, the DWR contracts that have been allocated to the Utility, but only if:

After assignment or assumption of the DWR contracts, the Utility receives a long-term issuer credit rating of at least A from S&P and A2 from Moody's;

The CPUC first has made a finding that the DWR contracts being assumed are just and reasonable; and

The CPUC has acted to ensure that the Utility receives full and timely recovery in its retail electricity rates of all costs of the DWR contracts without further review.

Under the proposed CPUC settlement agreement, the CPUC retains and, after any assignment or assumption of the DWR contracts, would retain the right to review the prudence of the Utility's administration and dispatch of the DWR contracts consistent with applicable law.

Headroom

The CPUC would agree and acknowledge that the headroom, surcharge, and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund. The proposed CPUC settlement notes that it is in the public interest to restore the Utility's financial health and to allow the Utility to recover, over a reasonable time, prior uncollected costs. For financial reporting purposes, these amounts that restore the Utility's financial health and recover previously written-off under-collected costs are referred to as headroom. The proposed CPUC settlement agreement defines headroom as the Utility's total net after-tax income reported under GAAP, less earnings from operations, (as has been historically define d by PG&E Corporation in its earnings press release, a non-GAAP financial measure), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided the calculation will reflect the outcome of the Utility's 2003 GRC. The proposed CPUC settlement agreement provides that if headroom accrued by the Utility during 2003 is greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom is less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in future rates.

Dismissal of Filed Rate Case, Other Litigation, and Regulatory Proceedings

On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement is no longer subject to appeal, the Utility would dismiss with prejudice its case against the CPUC Commissioners asserting the "filed rate doctrine," withdraw the original plan of reorganization, and dismiss other pending proceedings. In exchange, on or before January 1, 2004, the CPUC would establish and authorize the collection of the Regulatory Asset and the Utility's rate base for its electricity generation, and on or as soon as practicable after the effective date, resolve phase 2 of the pending Annual Transition Cost Proceeding in which the CPUC is reviewing the reasonableness of the Utility's procurement costs incurred during the energy crisis with no adverse impact on the Utility's cost recovery as filed.

On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement is no longer subject to appeal, PG&E Corporation, the Utility, and the CPUC would execute mutual releases and dismissals with prejudice of specified claims, actions, or regulatory proceedings arising out of or related in any way to the energy crisis or the implementation of AB 1890, including the CPUC's investigation into past holding company actions during the California energy crisis (but only as to past actions, not prospective matters).

Environmental Measures

The Utility would agree to implement three environmental enhancement measures:

The Utility would encumber with conservation easements or donate approximately 140,000 acres of land to public agencies or non-profit conservation organizations;

The Utility would establish a California non-profit corporation to oversee the environmental enhancements associated with these lands and fund it with $70 million in cash over 10 years, although the Utility would be entitled to recover these payments in rates; and

The Utility would create a non-profit corporation funded with $15 million payable by the Utility over five years dedicated to support research and investment in clean energy technology, primarily in the Utility's service territory.

Of the approximately 140,000 acres referred to in the first bullet, approximately 45,000 acres may be either donated or encumbered with conservation easements. The remaining land contains the Utility or a joint licensee's hydroelectric generation facilities and may only be encumbered with conservation easements.

Waiver of Sovereign Immunity

The CPUC would agree to waive all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties' rights under, the proposed CPUC settlement agreement, the Settlement Plan, or the Bankruptcy Court's order confirming the Settlement Plan (Confirmation Order). The CPUC also would consent to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the Bankruptcy Court. The CPUC's waiver would be irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off, or any other legal process with respect to the enforcement of, or other determination of the parties' rights under, the proposed CPUC settlement agreement, the Settlement Plan, or the Confirmation Order. The proposed CPUC settlement agreement contemplates tha t neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties' rights under the proposed CPUC settlement agreement, the Settlement Plan, or the Confirmation Order.

Term and Enforceability

The proposed CPUC settlement agreement generally would terminate nine years after the effective date of the Settlement Plan, except that the rights of the parties to the proposed CPUC settlement agreement that vest on or before termination, including any rights arising from any default under the proposed CPUC settlement agreement, would survive termination for the purpose of enforcement. The parties would agree that the Bankruptcy Court would have jurisdiction over the parties for all purposes relating to enforcement of the proposed CPUC settlement agreement, the Settlement Plan, and the Confirmation Order. The parties also would agree that the proposed CPUC settlement agreement, the Settlement Plan, or any order entered by the Bankruptcy Court contemplated or required to implement the proposed CPUC settlement agreement or the Settlement Plan would be irrevocable and binding on the parties and enforceable under federal law, notwithstanding any contrary state law or future decisions or orders of the CPUC.

Fees and Expenses

The proposed CPUC settlement agreement would require the Utility to reimburse PG&E Corporation and the CPUC for their respective professional fees and expenses incurred in connection with the Chapter 11 proceeding once the Settlement Plan is confirmed. Of such amounts, the amounts reimbursed to the CPUC (but not to PG&E Corporation) would be recovered from ratepayers over a reasonable time of up to four years. As of September 30, 2003, PG&E Corporation has incurred expenses of approximately $128 million on the Utility's Chapter 11 proceeding.

Conditions of the Effectiveness of the Settlement Plan

The Settlement Plan provides that it would not be confirmed by the Bankruptcy Court unless and until the following conditions are satisfied or waived:

The Bankruptcy Court enters an order or orders:

Approving the Settlement Plan, authorizing the Utility to execute, enter into, and deliver the Settlement Plan, and to execute, implement, and take all actions necessary or appropriate to give effect to the transactions contemplated by the Settlement Plan;

Approving and authorizing the execution of, and finding reasonable the terms and conditions of, the proposed CPUC settlement agreement; and

The Confirmation Order is, in form and substance, reasonably satisfactory to PG&E Corporation, the Utility, the OCC, and the CPUC and specifically includes certain matters.

The Settlement Plan also provides that it would not become effective unless and until the following conditions are satisfied or waived:

The effective date occurs on or before March 31, 2004;

All actions, documents, and agreements necessary to implement the Settlement Plan are effected or executed;

PG&E Corporation and the Utility have received all authorizations, consents, regulatory approvals, rulings, letters, no-action letters, opinions, or documents that they deem necessary to implement the Settlement Plan;

The Settlement Plan has not been modified in a material way since the date of confirmation;

The Utility has consummated the sale of the debt securities contemplated by the Settlement Plan;

S&P has issued a long-term issuer credit rating for the Utility of not less than BBB- and Moody's has issued an issuer rating for the Utility of not less than Baa3;

S&P and Moody's have issued credit ratings for the debt securities to be offered by the Utility of not less than BBB- and Baa3, respectively;

The CPUC has given final nonappealable approval of the proposed CPUC settlement agreement on behalf of the CPUC;

Each of the parties to the proposed CPUC settlement agreement has executed and delivered the settlement agreement;

The CPUC has given final nonappealable approval for all of the financings, securities, and accounts receivable programs provided for in the Settlement Plan; and

The CPUC has given final nonappealable approval for all rates, tariffs, and agreements necessary to implement the Settlement Plan.

The last six conditions cannot be waived, except that PG&E Corporation and the Utility can waive the right to the finality provisions regarding CPUC approvals.

PG&E Corporation and the Utility are unable to predict whether and when the proposed CPUC settlement agreement will become effective or whether the Settlement Plan will be confirmed or implemented. If the Settlement Plan is not confirmed, or if the CPUC does not approve the proposed CPUC settlement agreement and related rates, or if the CPUC takes actions materially inconsistent with the proposed CPUC settlement agreement in pending regulatory proceedings associated with the recovery of transition costs and surcharge revenues, or the allocation of DWR electricity to customers of investor-owned utilities (IOUs), as detailed in Note 6 below, then the Utility's financial condition and results of operations could be materially adversely affected.

NOTE 3: DEBT

On July 2, 2003, PG&E Corporation completed a private placement of $600 million of 6⅞ percent Senior Secured Notes due 2008 (Notes). The net proceeds of the offering of approximately $582 million, together with cash on hand, were used to repay the principal balance outstanding under PG&E Corporation's existing credit agreement of approximately $735 million. A pre-tax loss of approximately $89 million was recorded in the third quarter of 2003 to reflect the write-off of unamortized loan fees, loan discount, and prepayment costs. The payment resulted in the termination of PG&E Corporation's existing credit agreement and the release of liens on PG&E Corporation's shares of NEGT, Inc., as well as the prior lien on approximately 94 percent of the outstanding common stock of the Utility.

The following description is a summary of the material provisions of the indenture.

Principal, Maturity, and Interest

The Notes mature on July 15, 2008. Interest on the Notes accrues at the rate of 6⅞ percent per annum and is payable semi-annually in arrears on January 15 and July 15, commencing on January 15, 2004.

Additional Notes

The indenture governing the Notes permits PG&E Corporation to issue additional notes from time to time after this offering. Any such offering of additional notes will be subject to limitations as set forth in the covenants of the indenture and further discussed below.

Security

The Notes are secured by a perfected first-priority security interest in approximately 94 percent of the outstanding common stock of the Utility that is owned by PG&E Corporation. With respect to 35 percent of such common stock pledged for the benefit of the lenders, the holders have customary rights of a pledge of common stock, provided that certain regulatory approvals may be required in connection with any foreclosure on and any exercise of the right to vote such stock. With respect to the remaining 65 percent, such common stock has been pledged for the benefit of the holders, but the holders have no ability to control such common stock under any circumstances and do not have any of the typical rights and remedies of a secured creditor. However, the holders do have the right to receive any cash distributions associated with such common stock.

The Notes are effectively subordinated to all indebtedness and other obligations (including trade payables) of PG&E Corporation's subsidiaries. In the event of a bankruptcy, liquidation or reorganization of any of PG&E Corporation's subsidiaries, such subsidiary will pay the holders of its debt and its trade creditors before it will be able to distribute any of its assets to PG&E Corporation.

Redemption

At any time prior to July 15, 2006, PG&E Corporation may on one or more occasions redeem up to 35 percent of the aggregate principal amount of the Notes issued under the indenture at a redemption price of 106.875 percent of the principal amount, plus accrued and unpaid interest and additional interest, if any, to the redemption date, with the net cash proceeds of one or more public sales of capital stock for cash by PG&E Corporation after the issue date of the Notes, provided that:

At least 65 percent of the aggregate principal amount of the Notes issued under the indenture remains outstanding immediately after the occurrence of each such redemption (excluding Notes held by PG&E Corporation and its subsidiaries); and

Any such redemption occurs within 120 days of the date of the closing of such sale of capital stock.

At any time prior to July 15, 2006, PG&E Corporation may, at its option, redeem all or a portion of the Notes at the make-whole price, specified in the indenture, plus accrued and unpaid interest to the redemption date. Except as described in the preceding paragraphs, the Notes will not be redeemable at PG&E Corporation's option prior to July 15, 2006.

On and after July 15, 2006, PG&E Corporation may redeem all or a part of the Notes at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest and additional interest, if any, on the Notes redeemed, if redeemed during the 12-month period beginning on July 15 of the years indicated below:

Year		Percentage

2006		103.438%
2007		101.719%

PG&E Corporation is not required to make mandatory redemption or sinking fund payments with respect to the Notes. In the case of a change of control, spin-off, or reorganization event, PG&E Corporation is required to offer to repurchase the Notes.

Restrictions

PG&E Corporation and its restricted subsidiaries, as defined in the indenture, are subject to the restrictive covenants of the indenture. PG&E Corporation's principal subsidiaries, the Utility and NEGT, Inc., are defined as unrestricted subsidiaries and are not subject to many of the restrictive covenants in the indenture. The Notes contain limitations, among other restrictions, on the ability of PG&E Corporation and its restricted subsidiaries to grant liens, consolidate, merge, sell assets, declare or pay dividends, incur indebtedness, and perform certain affiliate transactions.

Dividends

The Note indenture prohibits PG&E Corporation from declaring or paying dividends unless, as specified in the indenture, it has either met certain financial criteria, and no default is outstanding under the indenture or would result from the payment of such dividends or a specified exception applies. These specified exceptions include circumstances in which: (1) PG&E Corporation achieves an investment grade credit rating, or (2) following the implementation of the Utility's Settlement Plan, PG&E Corporation pays any dividend from the proceeds of cash distributions to PG&E Corporation from the Utility. Certain of these exceptions also include the requirement that no default is outstanding under the indenture or would result from the payment of such dividends.

Covenant Termination

Upon the first date the Notes are rated BBB- or better by S&P and Baa3 or better by Moody's and no material default has occurred and is continuing under the indenture, PG&E Corporation and its restricted subsidiaries will cease to be subject to certain restrictive covenants of the indenture, such as restrictions on dividends, payments, asset sales, and affiliate transactions. In addition, after the conditions are satisfied, PG&E Corporation may secure additional indebtedness using the Utility's common stock as collateral in an amount up to 15 percent of its consolidated tangible assets, defined as its total consolidated assets less goodwill and intangible assets.

Events of Default

The Notes contain certain events of default, including PG&E Corporation's failure to pay any indebtedness of $50 million or more. Upon certain events of default, the Notes will become due and payable immediately.

Registration Rights, Additional Interest

Pursuant to a Registration Rights Agreement, PG&E Corporation has agreed to file an exchange offer registration statement with the SEC with respect to the Notes by April 27, 2004, and must use its best efforts to cause such registration statement to be declared effective by June 26, 2004. If PG&E Corporation does not register the Notes in accordance with the Registration Rights Agreement, PG&E Corporation will be required to pay additional interest of up to approximately 1 percent annually, until the Notes have been registered.

NOTE 4: DISCONTINUED OPERATIONS

On July 7, 2003, PG&E Corporation's representatives who previously served on the NEGT, Inc. Board of Directors resigned and were replaced with Board members who are not affiliated with PG&E Corporation. Subsequently, on July 8, 2003, NEGT, Inc. 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. On July 29, 2003, two additional subsidiaries of NEGT, Inc. also filed voluntary Chapter 11 petitions. Pursuant to Chapter 11, NEGT, Inc. and those subsidiaries 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 July 8, 2003, NEGT, Inc. also filed a proposed plan of reorganization with the Bankruptcy Court that, if implemented, would eliminate PG&E Corporation's equity interest in NEGT, Inc. On October 3, 2003, the Bankruptcy Co urt authorized PG&E NEG to change its name to NEGT, Inc. The change reflects NEGT, Inc.'s pending separation from PG&E Corporation.

As a result of NEGT, Inc.'s Chapter 11 filing and the resignation of PG&E Corporation's representatives who previously served on the NEGT, Inc. Board of Directors, PG&E Corporation no longer retains significant influence over the ongoing operations of NEGT, Inc. PG&E Corporation anticipates that the Bankruptcy Court will approve NEGT, Inc.'s proposed plan of reorganization, or a plan with similar equity loss provisions for PG&E Corporation. Therefore, as of July 8, 2003, PG&E Corporation has classified NEGT, Inc. as a discontinued operation, deconsolidated the operations of NEGT, Inc. and has reflected its ownership interest in NEGT, Inc. utilizing the cost method of accounting.

As a result of NEGT, Inc.'s Chapter 11 filing on July 8, 2003, and the proposed loss of equity ownership provided for in NEGT, Inc.'s plan of reorganization, PG&E Corporation considers its investment in NEGT, Inc. to be an abandoned asset and has accounted for NEGT, Inc. as a discontinued operation in accordance with SFAS No. 144. Under the provisions of SFAS No. 144, the operating results of NEGT, Inc. and its subsidiaries are reported as discontinued operations in the Consolidated Statements of Income for all prior periods reported. In addition, all prior period assets and liabilities of NEGT, Inc., shown for comparative purposes, are classified as discontinued operations.

NEGT, Inc. is no longer consolidated by PG&E Corporation in its consolidated financial statements. The accompanying September 30, 2003, Consolidated Balance Sheet of PG&E Corporation does not reflect the separate assets and liabilities of NEGT, Inc.; rather, a liability of approximately $1.2 billion is reflected, which represents the losses of NEGT, Inc. recognized by PG&E Corporation in excess of its investment in and advances to NEGT, Inc. In addition, accumulated OCI includes a net debit of approximately $77 million at September 30, 2003, related to NEGT, Inc. The accompanying Consolidated Statements of Income of PG&E Corporation for the three- and nine-month periods ended September 30, 2003, and 2002 present the operations of NEGT, Inc. through July 7, 2003 as discontinued operations. PG&E Corporation's investment in NEGT, Inc. will not be affected by changes in NEGT, Inc.'s future financial results, other than (1) investments in or dividends from NEGT, Inc., or (2) income tax es PG&E Corporation may be required to pay if the Internal Revenue Service disallows certain deductions or tax credits attributable to NEGT, Inc. and its subsidiaries for past tax years that are incorporated into PG&E Corporation's consolidated tax returns.

Upon implementation of NEGT, Inc.'s plan of reorganization that eliminates PG&E Corporation's equity in NEGT, Inc., PG&E Corporation will reverse its investment in NEGT, Inc. and the amounts included in accumulated OCI and, as a result, recognize a one-time net non-cash gain to earnings from discontinued operations. Any unrealized deferred tax assets relating to the losses of NEGT, Inc. that have been recognized through July 7, 2003, will reverse at the time PG&E Corporation releases its ownership interest in NEGT, Inc. This reversal of deferred tax assets will partially offset any one-time gain recognized when PG&E Corporation writes off its net investment in NEGT, Inc.

NEGT, Inc. Operating Results

Included within Earnings from Discontinued Operations on the Consolidated Statements of Income of PG&E Corporation are NEGT, Inc.'s operating results, summarized below:

	Seven days ended July 7,		Three months ended September 30,		188 Days ended July 7,		Nine months ended September 30,

(in millions)	2003		2002		2003		2002

Operating Revenues	$	35	$	524	$	786	$	1,390
Loss Before Income Taxes	(8)		(98)		(595)		(413)

Prior to the abandonment of NEGT, Inc. by PG&E Corporation, NEGT, Inc. 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 July 7, 2003, and the other previously discontinued operations through the respective disposal dates. NEGT, Inc.'s pre-tax loss includes the following gains and losses on disposal of those subsidiaries: a $19 million pre-tax gain on disposal related to the sale of Mountain View Power Partners, LLC in January 2003, an additional $3 million pre-tax loss on disposal related to the sale of PG&E Energy Trading, Canada Corporation in the first quarter of 2003, and a $9 million pre-tax loss on disposal related to the sale of certain Ohio generating plants and related equipment in the second quarter of 2003.

During the second quarter of 2003, NEGT, Inc. determined that its historical financial reporting presentation of revenues and expenses related to hedging and certain ISO purchase and sales transactions had not been consistent. Certain types of transactions had been reported on a net basis (whereby revenues had been offset by the related expense item) and other types of transactions had been reported on a gross basis. In order to provide a consistent reporting of its trading and hedging transactions, NEGT, Inc. adopted a net presentation approach for such transactions. PG&E Corporation believes that this method of presentation is preferable under the circumstances. Adopting this change reduced previously reported revenues and expenses of NEGT, Inc. by $643 million for the nine months ended September 30, 2002, and $381 million for the three months ended September 30, 2002. In addition, adjustments were made principally for the effects of transactions that had not previously been eliminated in conso lidation by NEGT, Inc. Such adjustments decreased previously reported revenues and expenses by $339 million for the nine months ended September 30, 2002, and $166 million for the three months ended September 30, 2002. These changes did not result in any change in the consolidated operating income or net income, the Consolidated Balance Sheets, or the Consolidated Statements of Cash Flows.

In October 2002, the EITF rescinded EITF 98-10. Energy trading contracts that are derivatives in accordance with SFAS No. 133 continue to be accounted for at fair value under SFAS No. 133. Contracts that previously were marked to market as trading activities under EITF 98-10 and that did not meet the definition of a derivative are accounted for at cost. For PG&E Corporation, the majority of trading contracts are derivative instruments as defined in SFAS No. 133. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading purposes, which continue to be accounted for in accordance with SFAS No. 133. The reporting requirements associated with the rescission of EITF 98-10 were applied prospectively for all EITF 98-10 energy trading contracts entered into after October 25, 2002, although the number of energy trading contracts subject to the prospective implementation was considered immaterial.

NEGT, Inc. Balance Sheet Information

The following table reflects the condensed assets and liabilities of NEGT, Inc. as reflected in current and noncurrent assets and liabilities in the accompanying Consolidated Balance Sheet of PG&E Corporation at December 31, 2002:

Balance at

(in millions)

December 31,
2002

Assets

Total current assets

$

3,029

Net property, plant and equipment

2,939

Total other non-current assets

1,944

Total assets

7,912

Liabilities

  Debt in default

4,230

  Long-term debt, classified as current

17

  Other current liabilities

2,410

Total current liabilities

6,657

  Long-term debt

630

  Price risk management

305

  Other non-current liabilities and deferred credits

972

Total non-current liabilities

1,907

Total liabilities

8,564

Excess of liabilities over assets

$

(652)

Commitments and Contingencies of NEGT, Inc.

NEGT, Inc. was in default under various debt agreements and guaranteed equity commitments totaling approximately $5.6 billion, of which approximately $2.8 billion was debt that is non-recourse to NEGT, Inc. At July 8, 2003, NEGT, Inc. did not have sufficient cash to meet its financial obligations and ceased making payments on its debt and equity commitments. PG&E Corporation is not a party to these agreements, nor does it anticipate any obligation related to these agreements.

NEGT ET, a NEGT, Inc. subsidiary, entered into tolling agreements with several counterparties under which, at its discretion, NEGT ET supplied the fuel to power plants and then sold the plant's output in the competitive market. On July 8, 2003, NEGT ET petitioned the Bankruptcy Court to reject all remaining tolling agreements. On August 6, 2003, the Bankruptcy Court approved NEGT ET's motion. Although each tolling agreement allows for the determination of a termination payment, PG&E Corporation is not a party to these agreements, nor does it anticipate any obligation related to these agreements.

NEGT, Inc. and certain subsidiaries have provided guarantees in support of NEGT ET's energy trading and non-trading activities related to NEGT, Inc.'s merchant energy operations. With its Chapter 11 filing on July 8, 2003, NEGT ET defaulted on numerous trading agreements. The amounts due as a result of these defaults will be determined and resolved in the context of NEGT ET's Chapter 11 filing. 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, Inc. financial results are no longer consolidated in those of PG&E Corporation following the July 8, 2003, Chapter 11 filing of NEGT, Inc. NEGT, Inc.'s financial results through July 7, 2003, are reflected in Discontinued Operations. Subsequent to July 7, 2003, the only risk management activities currently reported by PG&E Corporation are related to Utility non-trading activities.

Non-Trading Activities

At September 30, 2003, the Utility had $8 million of cash flow hedges associated with natural gas commodity price risk, the longest of which extend through March 2004. These contracts are presented at fair value on PG&E Corporation's and the Utility's Consolidated Balance Sheets in other current assets and regulatory liabilities. The fair value of these hedges is recorded in regulatory liabilities because the hedges are recoverable through rates. At September 30, 2002, the Utility did not have any cash flow hedges.

There were no ineffective portions of changes in amounts of the Utility's cash flow hedges for the three- and nine-month periods ended September 30, 2003, and 2002.

The Utility has certain non-trading contracts that are exempt from the SFAS No. 133 fair value requirements under the normal purchases and sales exception and thus have no mark-to-market effect on earnings. Additionally, the Utility has other non-trading derivative contracts that do not qualify for cash flow hedge accounting or the normal purchase and sales exception to SFAS No. 133. These derivatives are reported in earnings on a mark-to-market basis.

Credit Risk

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if counterparties failed to perform their contractual obligations. These obligations are reflected as Accounts Receivable - Customers, net and notes receivable included in Other Noncurrent Assets - Other on the Consolidated Balance Sheets of PG&E Corporation and the Utility.

PG&E Corporation had gross accounts receivable of $1.9 billion at September 30, 2003 and $2.0 billion at December 31, 2002. The majority of the accounts receivable are associated with residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of $60 million at September 30, 2003, and $59 million at December 31, 2002, were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in Northern California. However, the risk of material loss due to non-performance from these customers is not considered likely.

The Utility conducts business with customers or vendors primarily in the energy industry, including other California IOUs, municipal utilities, energy trading companies, financial institutions, and oil and 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 Utility manages credit risk for its largest customers (counterparties) by assigning credit limits to counterparties based on an evaluation of a potential counterparty's financial condition, net worth, credit rating, and other credit criteria as deemed appropriate. Each counterparty's credit limit and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure is calculated daily, and in the event that 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 the counterparty to post 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 counterparty as the current mark-to-market value of the contract (that is, the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, prior to the application of the counterparty's credit collateral. During the nine-month period ended September 30, 2003, the Utility recognized no losses due to contract defaults or bankruptcies of counterparties. At September 30, 2003, the Utility had two investment grade counterparties that represented 33 percent of the Utility's net credit exposure and two below-investment grade counterparties that represented 24 percent of the Utility's net credit exposure.

The schedule below summarizes the Utility's credit risk exposure to counterparties that are in a net asset position, as well as the Utility's credit risk exposure to counterparties with a greater than 10 percent net credit exposure, at September 30, 2003, and December 31, 2002:

(in millions)		Gross Credit Exposure Before Credit Collateral ⁽¹⁾		Credit Collateral		Net Credit Exposure ⁽²⁾		Number of Counterparties >10 percent	Net Exposure of Counterparties >10 percent


September 30, 2003 ⁽³⁾		$	141	$	8	$	133	4	$	76
December 31, 2002		288		113		175		2	55

⁽¹⁾	Gross credit exposure equals mark-to-market value, notes receivable, and net (payables) receivables where netting is 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 incurred prior to the Utility's Chapter 11 filing 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.
⁽³⁾	Excludes post-petition exposures to Enron.

The schedule below summarizes the credit quality of the Utility's net credit risk exposure to counterparties at September 30, 2003, and December 31, 2002.

Credit Quality ⁽¹⁾		Net Credit Exposure ⁽²⁾			Percentage of Net Credit Exposure

(in millions)

September 30, 2003
Investment grade ⁽³⁾		$	98	74%
Non-investment grade			35	26%

Total		$	133	100%




December 31, 2002
Investment grade ⁽³⁾		$	111	63%
Non-investment grade			64	37%

Total		$	175	100%




⁽¹⁾	Credit ratings are determined by using publicly available credit ratings of the counterparty. If the counterparty provides a guarantee by a higher rated entity (e.g., its parent), the rating determination is based on the rating of its 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 quality.

NOTE 6: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments and contingencies in connection with agreements entered into supporting the Utility's operating activities. PG&E Corporation has limited financial commitments relating to NEGT, Inc.'s operating activities. These commitments are discussed more fully in PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended. The following summarizes PG&E Corporation's and the Utility's material contingencies and canceled, new, and significantly modified commitments since the combined 2002 Annual Report on Form 10-K, as amended, was filed.

Commitments
Utility

Natural Gas Supply and Transportation Commitments - The Utility purchases natural gas directly from producers and marketers in both Canada and the United States. The composition of the portfolio of natural gas procurement contracts has fluctuated, generally based on market conditions.

The Utility also has long-term gas transportation service agreements with various Canadian and interstate pipeline companies. These companies are responsible for transporting the Utility's gas to the California border. These agreements include provisions for payment of fixed demand charges for reserving firm pipeline capacity as well as volumetric transportation charges. The total demand charges that the Utility will pay each year may change due to changes in regulated tariff rates.

At September 30, 2003, the Utility's obligations for natural gas purchases and gas transportation services were as follows:

(in millions)

2003	$	247
2004		478
2005		89
2006		26
2007		7
Thereafter		-

Total	$	847

The Utility provides a $10 million standby letter of credit and a pledge of its natural gas customer accounts receivable as security for its purchases of natural gas from certain suppliers. The Utility's natural gas inventory also may be pledged, but only if the Utility's natural gas customer accounts receivable are less than the amount that the Utility owes to the natural gas suppliers secured by the pledge. To date, the accounts receivable pledge has been sufficient. The pledge amounts were $198 million at September 30, 2003, and $513 million at December 31, 2002. The CPUC authorized the Utility to pledge its natural gas customer accounts receivable and natural gas inventory, if necessary, until the earlier of:

May 1, 2004;

15 days after an upgrade of the credit rating of the Utility's mortgage bonds to at least BBB- by S&P or Baa3 by Moody's;

The effective date of a plan of reorganization; or

The dismissal or conversion of the Utility's Chapter 11 proceeding.

Transmission Control Agreement - The Utility entered into a Transmission Control Agreement (TCA) with the ISO and other participating transmission owners. As a transmission owner, the Utility is required to give two years notice if it wishes to withdraw from the TCA. Under this agreement, the transmission owners, which also include Southern California Edison (SCE) and San Diego Gas & Electric Company and several municipal utilities, assign operational control of their electric 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 (RMR) agreements between the ISO and owners of the plants subject to RMR agreements (RMR Plants). Under the RMR agreements, RMR Plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO's demand.

At September 30, 2003, the ISO has RMR agreements that obligate the Utility for approximately $868 million during the period October 1, 2003, to September 30, 2005.

It is possible that the Utility may receive a refund of RMR costs previously paid to the ISO. In June 2000, a FERC Administrative Law Judge (ALJ) issued an initial decision that would require the subsidiaries of the Mirant Corporation (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 for the availability of Mirant's generating facilities under the RMR agreements. If the FERC were to affirm the ALJ's initial decision, the Utility would expect refunds of approximately $300 million, including interest. On July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 of the Bankruptcy Code. The Utility is unable to predict at this time when the FERC will issue a final decision on this issue, what that decision will be, and the amount of refunds the Utility will ultimately receive, which may be impacted by Mirant's Chapter 11 filing. Any refunds received would be used to reduce previously under-collected transition and procurement costs or to lower RMR costs depending on the time period covered by the refunds.

Irrigation Districts and Water Agencies - The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts' and water agencies' debt service requirements, whether or not any energy is supplied (subject to the supplier's retention of the FERC's authorization), and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031.

At September 30, 2003, the undiscounted future expected irrigation districts and water agencies payments were as follows:

(in millions)	Operations & Maintenance		Debt Service

2003	$	11	$	7
2004	41		28
2005	35		26
2006	31		26
2007	30		27
Thereafter	214		168

Total	$	362	$	282

Tri-Valley Project - The Tri-Valley project is a multi-year project to site and construct electric transmission and distribution facilities to serve electric load growth in the area of Livermore, San Ramon, Pleasanton and the adjacent areas. The Bankruptcy Court approved the capital expenditure of $135.9 million, which includes Utility labor and supplier equipment, in February 2002. At September 30, 2003, the Utility's total commitments for third-party services and equipment for the project were approximately $21 million, payable through 2005.

Electricity Purchases to Meet Demand - On January 1, 2003, the Utility resumed the function of procuring electricity to meet the portion of its customers' needs that is not covered by the combination of the allocation of electricity from existing DWR contracts and the Utility's own electric generation resources and contracts. To meet this requirement, the Utility entered into contracts for fuel supply, capacity, and transmission rights. In order to enter into these contracts, the Utility has posted collateral with the California ISO and several other counterparties. These contracts, with terms of one year or less, did not have a material impact on the Utility's commitments previously disclosed in its 2002 Annual Report on Form 10-K, as amended.

In August 2003, the Utility filed an application requesting that the CPUC approve the Utility's 2004 Energy Resource Recovery Account (ERRA) forecast revenue requirement of $1.5 billion associated with the Utility's 2004 short-term procurement plan and approve as reasonable the Utility's ERRA recorded costs for the period from January 2003 through May 2003. The CPUC's review of the Utility's procurement activities will examine the Utility's least-cost dispatch of the resource portfolio, fuel expenses for the Utility's electricity generation, contract administration, including administration of the DWR allocated contracts, the Utility's existing QF contracts and other power purchase agreements, renewable energy contracts, and the decision to engage in market transactions in the context of the Utility's overall prudent contract administration and least-cost dispatch of generation resources. The Utility has also asked the CPUC to approve its proposed revenue requirement of $840 million to recover the 2004 costs related to the above-market generation and procurement costs and certain other generation-related costs.

In June 2003, the CPUC issued a decision pursuant to SB 1078 that adopts the framework for implementing a Renewable Portfolio Standard (RPS) program. The decision requires the Utility to increase procurement of renewable energy by at least 1 percent of its retail sales per year. By the end of 2017, the Utility must be procuring at least 20 percent of its total electricity from renewable resources. Under SB 1078, the Utility is not obligated to purchase additional renewable energy until it received an investment grade credit rating. However, under subsequently enacted SB 67, the Utility may be required to purchase additional renewable energy once it is able to do so on reasonable terms and the renewable energy contracts will not impair the restoration of its creditworthiness. Until that time, the Utility will accumulate an annual procurement target (APT) based on 1 percent of annual retail sales. When the Utility receives an investment grade credit rating or the CPUC determines that the SB 67 require ments are satisfied, the Utility expects to enter into purchase contracts for renewable energy to meet its accumulated APT.

Although the Utility cannot predict what the terms, including price, of such contracts would be, the decision requires that the procurement price under such contracts be at or below a market price benchmark established by the CPUC after the bids have been received. If the Utility exceeds its APT, it can apply the excess to meet the APT in future years. For under-procurement, the decision allows IOUs to carry over an annual deficit of 25 percent to the next three years without explanation. Failure to meet minimum APTs without prior CPUC approval would result in an automatic penalty of $0.05 per kWh, subject to an annual penalty cap of $25 million. The Utility currently estimates that the annual 1 percent increase in renewable resource electricity in its portfolio will initially require between 80 and 100 megawatts (MW) of additional renewable capacity to be added per year.

The CPUC approved offers submitted by the Utility that were sufficient to meet the Utility's 2003 renewable energy requirement in December 2002. In September 2003, the Utility submitted to the CPUC for approval several renewable contracts pursuant to an assigned commissioner ruling in August 2003 that permitted bilateral negotiations with renewable suppliers prior to the implementation of renewable energy portfolio standard requirements. The CPUC approved the contracts in October 2003.

Contingencies

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

Surcharge Revenues

In January 2001, the CPUC increased electric rates by $0.01 per kWh, in March 2001 by another $0.03 per kWh, and in May 2001 by an additional $0.005 per kWh. The use of these surcharge revenues was restricted to "ongoing procurement costs" and "future power purchases." In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. Based on these CPUC decisions and an agreement between the CPUC and SCE, another IOU, in which SCE was allowed to use its $0.005 per kWh surcharge to offset its DWR revenue requirement, the Utility has continued to recognize revenues related to the $0.01 per kWh, $0.03 per kWh, and $0.005 per kWh surcharges after the statutory end of the retail electric rate freeze, which was March 31, 2002, even without considering the proposed settlement agreement in the Utility' s Chapter 11 proceeding (discussed in Note 2). As such, the Utility has not recorded a regulatory liability or a reserve for the potential refund of these surcharge revenues, or any portion thereof, as of September 30, 2003. From January 2001 to September 30, 2003, the Utility recognized total surcharge revenues of approximately $7.5 billion, pre-tax.

Under the proposed settlement agreement discussed in Note 2, the CPUC would agree and acknowledge that the headroom, surcharge, and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund. The proposed CPUC settlement agreement notes that it is in the public interest to restore the Utility's financial health and to allow the Utility to recover, over a reasonable time, prior uncollected costs. For financial reporting purposes, these amounts that restore the Utility's financial health and recover previously written-off under-collected costs are referred to as headroom. The proposed CPUC settlement agreement defines headroom as the Utility's total net after-tax income reported unde r GAAP, less earnings from operations (as has been historically defined by PG&E Corporation in its earnings press release, a non-GAAP financial measure), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided the calculation will reflect the outcome of the Utility's 2003 GRC. The proposed CPUC settlement agreement provides that if headroom accrued by the Utility during 2003 is greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom is less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in future rates.

In July 2003, a CPUC Commissioner issued a proposed decision finding that the retail electric rate freeze ended on January 18, 2001. The proposed decision also provides that the CPUC would determine in a separate proceeding the extent and disposition of costs previously defined as uneconomic, transition, or stranded. The proposed decision contemplates that the separate proceeding would also determine whether the recovery of these costs has been fully addressed or resolved in the Utility's Chapter 11 proceeding or in other CPUC proceedings. The Utility has filed comments suggesting that the CPUC defer its decision on these issues pending the CPUC's consideration of the proposed CPUC settlement agreement and the implementation of the Settlement Plan. The Utility cannot predict the ultimate outcome of this proceeding.

In August 2003, the California Supreme Court issued a decision on questions certified to it by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) regarding the validity of a settlement agreement between the CPUC and SCE. The decision concluded that the CPUC had the authority to enter into a settlement agreement with SCE that allowed SCE to recover under-collected purchased power and generation-related transition costs beyond the end of the rate freeze in light of the provisions of AB 1890, which prohibited post-freeze recovery of transition and procurement costs, and that the settlement agreement did not violate California law. This matter has now been returned to the Ninth Circuit for final disposition. In October 2003, the California Supreme Court denied a petition for rehearing of its decision that had been filed by The Utility Reform Network (TURN).

The Utility's ability to retain its surcharge revenues may be adversely affected if the proposed CPUC settlement agreement and Settlement Plan are not implemented or if, either in response to certain judicial decisions or on its own initiative, the CPUC changes its interpretation of law or otherwise seeks to change the Utility's overall retail electric rates retroactively. If the proposed CPUC settlement agreement is not approved and the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially adversely affected.

2003 General Rate Case

In the Utility's 2003 GRC, the CPUC will determine the amount of authorized base revenues the Utility can collect from ratepayers to recover its basic business and operational costs for gas and electric distribution operations for 2003 and succeeding years. In addition, the CPUC also will determine in this 2003 GRC the amount of authorized base revenues the Utility can collect from ratepayers to recover its basic business and operational costs for the Utility's retained generation.

In September 2003, the Utility and various intervenors (TURN, the CPUC's Office of Ratepayer Advocates (ORA), Aglet Consumer Alliance, the Modesto Irrigation District, the Natural Resources Defense Council, and the Agricultural Energy Consumers Association) filed a joint motion with the CPUC seeking approval of a settlement agreement these parties entered into in the Utility's 2003 GRC proceeding (2003 GRC settlement agreement), also filed with the CPUC. The parties reached agreement on all disputed economic issues related to the electricity and natural gas distribution revenue requirement of the 2003 GRC, with the exception of the Utility's request that the CPUC include the costs of a pension contribution in the Utility's revenue requirement. The CPUC will resolve the pension contribution issue, as well as other issues raised by non-settling intervenors, based upon briefs submitted on September 17, 2003, and reply briefs submitted on October 8, 2003, in its final decision and the Utility's GRC revenue requirements will be adjusted appropriately.

The 2003 GRC settlement agreement proposes that the Utility would receive a total 2003 revenue requirement of approximately $2.5 billion for electric distribution operations, representing a $236 million increase in the Utility's electric distribution revenue requirements over the current authorized amount. The settlement agreement provides that the amount of electricity distribution rate base on which the Utility would be entitled to earn an authorized rate of return would be $7.7 billion, based on recorded 2002 plant and including net weighted average capital additions for 2003 of $292 million. The 2003 GRC settlement agreement also provides that the Utility will implement a new balancing account, effective January 1, 2004, to ensure that the Utility recovers its authorized electric distribution revenue requirements regardless of the level of sales.

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

If the Utility prevails on the pension contribution issue, an additional revenue requirement of approximately $75 million would be allocated among electric distribution, gas distribution, and electric generation operations.

The parties have agreed that the Utility's next GRC will be to determine rates for test year 2007.

Only one party, the DWR, filed comments on the settlement agreement. The parties responded to these comments on October 7, 2003. Depending on the CPUC's review of these comments, a hearing may be held regarding the settlement. PG&E Corporation and the Utility are unable to predict the outcome of this matter.

In another phase of the GRC addressing how the Utility responds to storm outages and other reliability issues, the Utility reached an agreement with ORA that would allow the Utility to recover up to $9 million in 2003, with a lower cap of up to $2.3 million in each of the years 2004, 2005, and 2006. The Utility also reached an agreement with the California Coalition of Utility Employees that proposes a reliability performance incentive mechanism for the Utility beginning in 2004 through 2009. Under the proposed incentive mechanism, the Utility would receive a maximum reward or penalty of $42 million each year depending on whether it met the improvement targets on its outage duration and frequency performance. In order to provide the Utility the opportunity to achieve the improvement targets, the agreement provides for up to $27 million in additional revenues each year of the incentive mechanism (to be recorded in a one-way balancing account) to be spent exclusively on reliability improvement activities . Both of these agreements are pending CPUC approval.

In December 2002, the CPUC ordered that the 2003 GRC be effective January 1, 2003. The parties have requested that the CPUC issue a final decision approving the settlement agreement and resolve all remaining issues on or before February 5, 2004.

If the 2003 GRC settlement agreement is not approved by the CPUC, and if the Utility is unable to conform to the base revenue amounts adopted by the CPUC while maintaining safety and system reliability standards, the ability of the Utility to earn its authorized rate of return for the years until the next GRC would be adversely affected.

Allocation of DWR Electricity to Customers of the IOUs

In September 2002, the CPUC issued a decision to allocate the electricity provided under existing DWR contracts to the customers of the IOUs. The DWR retains legal and financial responsibility for these contracts.

Under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the CPUC could require the Utility to accept assignment of, or assume legal and financial responsibility for, the DWR allocated contracts for which the Utility currently acts as billing and collection agent, but only if:

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 contracts being assumed are just and reasonable; and

The CPUC has acted to ensure full and timely recovery in the Utility's retail electricity rates of all contract costs without further review.

Under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the CPUC retains, and after any assignment or assumption of DWR contracts, the CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law.

Nuclear Insurance

The Utility has several types of nuclear insurance for its Diablo Canyon Power Plant and Humboldt Bay Power Plant. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (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 annual premiums of up to $36.7 million.

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

Under the Price-Anderson Act (Act), public liability claims from a nuclear incident are limited to $10.9 billion. As required by the Act, the Utility has purchased the maximum available public liability insurance of $300 million for Diablo Canyon Power Plant. The balance of the $10.9 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the 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 the Diablo Canyon Power Plant has two nuclear reactors over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payment s in each year limited to a maximum of $20 million per incident. In February 2003, a provision extending the Act through the end of 2003 was adopted by the U.S. Congress. No other material terms of the Act changed as a result of the provision.

In addition, the Utility has $53.3 million of liability insurance for the retired nuclear generating unit at Humboldt Bay Unit 3 and has a $500 million indemnification from the Nuclear Regulatory Commission 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 (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 September 30, 2003, the Utility provided collateral in the form of approximately $365 million in surety bonds.

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 prior to the cancellation and has continued to apply the canceled bond amounts, totaling $185 million, toward the $365 million collateral requirement. At September 30, 2003, three additional active surety bonds totaling $180 million make up the Utility's collateral. On October 10, 2003, the Utility replaced one active $60 million surety bond with a cash deposit of $43 million. Total collateral at October 10, 2003, is $348 million, which consists of $305 million in surety bonds and $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 worke rs' compensation claims.

Balancing Account Reserves

In 2002, the CPUC ordered the Utility to create certain electric balancing accounts to track specific electric-related amounts, including revenue shortfalls from baseline allowance increases and costs related to the self-generation incentive program, for which the CPUC has not yet determined specific recovery methods. In the decisions ordering the creation of these balancing accounts, the CPUC indicated that the recovery method for these amounts would be determined in the future. Because the Utility cannot conclude that the amounts in these balancing accounts are considered probable of recovery in future rates, the Utility has reserved these balances by recording a charge against earnings. As of September 30, 2003, the reserve associated with these balancing accounts was approximately $262 million.

DWR Revenue Requirement

In 2001, as a result of the California energy crisis, the State of California authorized the DWR to purchase electricity to satisfy the difference between the aggregate electricity demand of the customers of the IOUs and the electricity those utilities had available for delivery from their own generation facilities and power purchase arrangements. California's AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. The DWR is legally and financially responsible for the long-term contracts it entered into before December 31, 2002. It pays for its costs of purchasing electricity from a revenue requirement collected from the Utility's electricity customers through a charge, called a power charge. Because the Utility acts as the billing and collection agent for the DWR's sales of its electricity to retail customers, amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues.

In December 2002, the CPUC issued a decision allocating approximately $2 billion of the DWR's 2003 $4.5 billion total statewide power charge-related revenue requirement to the Utility's customers. This revenue requirement includes the forecasted costs associated with the DWR allocated contracts during 2003. A December 2002 operating order required the Utility to perform the operational, dispatch, and administrative functions for the DWR allocated contracts beginning on January 1, 2003. In April 2003, the Utility and the DWR entered into a CPUC-approved operating agreement that supersedes the December 2002 operating order.

In July 2003, the DWR submitted a supplemental 2003 revenue requirement to the CPUC that reduced the amount of the total 2003 statewide power charge-related revenue the DWR was requesting by approximately $1 billion. In September 2003, the CPUC issued a decision that allocated this $1 billion reduction among the customers of the three California IOUs. The decision allocated approximately $444 million of the reduction to the customers of the Utility and required the Utility to provide a one-time bill credit to the Utility's customers to pass through the revenue requirement reduction. Prior ambiguities in the formula that determines the calculation of the Utility's collections payable to the DWR resulted in the Utility's underpayment of amounts the Utility paid the DWR through June 30, 2003. These ambiguities were resolved by the CPUC in a decision issued in September 2003. As of June 30, 2003, the Utility had accrued a $516 million reserve based on the Utility's estimate of underpayments. During Sept ember 2003, the Utility paid the DWR $77 million (which equals the $521 million shortfall ultimately determined to be due to the DWR, less the Utility's $444 million share of the DWR's $1 billion statewide revenue reduction). This $444 million share of the statewide revenue reduction has been returned to the Utility's customers in the form of bill credits issued in September and October 2003. The September 2003 decision also reduces the Utility's DWR power charge base remittance rate (before adjusting for direct access remittances for DWR power) from $0.105 per kWh to $0.095 per kWh effective immediately. This reduction in the remittance rate is in addition to the $444 million reduction described above. In September 2003, the Utility filed an advice letter proposing to further reduce the rate from $0.095 to $0.085 effective October 1, 2003, to account for amounts collected and remitted from direct access customers. This advice letter is currently pending before the CPUC.

The CPUC's allocation of the DWR's revenue requirement for the 2001-2002 period among the three California IOUs is subject to true-up adjustments based on the actual amount of power purchased by the DWR for the respective IOU's customers during the 2001-2002 period. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from the IOUs' electricity customers through a power charge and a bond charge. The CPUC originally allocated approximately 48.3 percent of the adopted DWR power charge revenue requirement for the 2001-2002 period, or about $4.4 billion, to the Utility.

In testimony submitted to the CPUC on October 15 and 22, 2003, the Utility estimated that it over-remitted $107 million in power charges to the DWR for the 2001-2002 period based on the allocation methodology applied by the CPUC in determining the allocation of the 2001-2002 DWR power charge revenue requirement. The Utility also proposed that the CPUC use a different allocation methodology under which the Utility estimates it over-remitted $211 million. Testimony submitted by SCE and other parties includes varying estimates of the Utility's true-up adjustment depending on the allocation methodology proposed. SCE calculated that the Utility over-remitted approximately $101 million in power charges to the DWR based on the allocation methodology applied by the CPUC in determining the allocation of the 2001-2002 DWR power charge revenue requirement. However, SCE also has proposed that the CPUC apply the allocation methodology used to allocate the DWR bond charge revenue requirement to allocate the bond pr oceeds among the customers of the IOUs, and under this methodology, has estimated that the Utility has under-remitted a net $453 million in DWR revenue requirements. The Utility's testimony noted that the CPUC had already rejected this proposal in its decision allocating the DWR's 2003 bond charge revenue requirements.

The Utility has proposed to include any true-up adjustments to the DWR's 2001-2002 revenue requirement in each IOU's allocation of the 2004 DWR revenue requirement to be collected through the 2004 DWR remittance rate. SCE supports this proposal, but San Diego Gas & Electric Company has proposed that any under-remittance that an IOU is determined to owe should be paid by the IOU immediately. CPUC hearings began on October 27, 2003, and the CPUC is expected to issue a decision on the 2001-2002 adjustments (as well as the 2004 DWR revenue requirement) in January 2004.

PG&E Corporation and the Utility expect that any amounts determined by the CPUC to have been under-remitted or over-remitted to the DWR by the Utility for the 2001-2002 period will be included in the DWR's revenue requirements in 2004 and subsequent periods, and collected or refunded on a going-forward basis from the Utility's customers. However, PG&E Corporation and the Utility are unable to predict the outcome of this matter. If the CPUC retroactively determines that the Utility has under-remitted a material amount to the DWR and orders the Utility to make a one-time true-up payment from cash on hand rather than collect the under-remitted amount from customers on a going-forward basis, the Utility's financial condition and results of operations would be materially adversely affected.

In October 2003, in connection with the Utility's prior lawsuit against the DWR, a California court of appeal issued a decision finding that the DWR is required by law to conduct a review to determine whether its revenue requirements are just and reasonable, but also finding that the California Administrative Procedure Act did not require the DWR to hold public hearings as part of its determination. If some of the DWR's costs are ultimately determined not to have been reasonably incurred and therefore disallowed from recovery from the Utility's customers, then the DWR's charges for these costs to ratepayers may be reduced within the Utility's service territory. The Utility cannot predict the ultimate outcome of this matter.

PG&E Corporation

As discussed above, PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with certain surety bonds and the Utility's obligations to pay workers' compensation claims.

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 (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 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 (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) 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.

The Utility had an undiscounted environmental remediation liability of $323 million at September 30, 2003, and $331 million at December 31, 2002. During the first three quarters of 2003, the liability was reduced by $8 million due to reassessment of the estimated cost of remediation and remediation payments. The $323 million accrued at September 30, 2003, includes (1) $105 million related to the pre-closing remediation liability associated with divested generation facilities, and (2) $218 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, 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 sites. Of the $323 million environmental remediation liability, the Utility has recovered $152 million and expects to recover approximate ly $114 million of the balance in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever it is possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refunds to ratepayers.

The cost of the hazardous substance remediation is difficult to estimate. The estimate depends on a number of uncertainties, including the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, which is based upon a range of reasonably possible outcomes. The Utility's undiscounted future costs could increase to as much as $418 million if (1) the other potentially responsible parties are not financially able to contribute to these costs, (2) the extent of contamination or necessary remediation is greater than anticipated, or (3) the Utility is found to be responsible for clean-up costs at additional sites.

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. Since the Utility's proposed plan of reorganization provides that the Utility intends to respond to these types of claims in the regular 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 unenforcea ble.

Diablo Canyon - The Utility's Diablo Canyon Power Plant employs a "once-through" cooling water system, which is regulated under a National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). This permit allows the Diablo Canyon Power Plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft Cease and Desist Order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon Power Plant's discharge was not protective of beneficial uses.

In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Diablo Canyon Power Plant protects beneficial uses and that the intake technology reflects the "best technology available," as defined in the Federal Clean Water Act. As part of the Central Coast Board settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On June 17, 2003, the settlement was fully executed by the Utility, the Central Coast Board, and the Attorney General's Office. In order for the Central Coast Board settlement agreement to become effective, among other things, the Central Coast Board must renew the Diablo Canyon Power Plant's NPDES permit. However, at its July 10, 2003, meeting, the Central Coast Bo ard did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement and the Central Coast Board requested its staff to develop additional information on possible mitigation measures.

The California Attorney General has filed a claim in the Utility's Chapter 11 proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with the Diablo Canyon Power Plant's operation of its cooling water system. The Utility is seeking withdrawal of this claim.

The Utility believes the ultimate outcome of this matter will not have a material impact on its consolidated financial position or results of operations.

Recorded Liability for Legal Matters

In accordance with SFAS No. 5, "Accounting for Contingencies," 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 $209 million at September 30, 2003, and $202 million at December 31, 2002.

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. The Utility's Chapter 11 filing on April 6, 2001, discussed in Note 2, automatically stayed the litigation described below against the Utility, except as otherwise noted.

Chromium Litigation

There are 14 civil suits pending against the Utility in several California state courts. 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 have filed proofs of claims with the Bankruptcy Court, most of whom are plaintiffs in the 14 chromium litigation cases. Approximately 1,035 of these claimants have filed proofs of claim requesting an approximate aggregate amount of $580 million and approximately another 225 claimants have filed claims for an "unknown amount."

In general, plaintiffs and claimants 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 death, or other injury and seek related damages. The Bankruptcy Court has granted certain claimants' motion for relief from stay so that the state court lawsuits pending before the Utility's Chapter 11 filing can proceed.

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 test trial has been scheduled to begin in March 2004. The Utility has filed 13 summary judgment motions challenging the claims of the trial test plaintiffs. Two of the 13 summary judgment motions are scheduled for hearing in December 2003, and two are scheduled for hearing in January 2004. The Utility also has filed a motion to dismiss the complaint in one of the cases that is scheduled to be heard on November 14, 2003.

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 September 30, 2003, 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.

Natural Gas Royalties Litigation

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

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

The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) incorrectly measured the volume and heat content of natural gas produced from federal or Native American leases. As a result, it is alleged that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases. The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties, and expenses associated with the litigation.

The relator has filed a claim in the Utility's Chapter 11 case for $2.5 billion, $2 billion of which is based upon the plaintiff's calculation of penalties sought against the Utility.

PG&E Corporation and the Utility believe the allegations to be without merit and intend to present a vigorous defense. PG&E Corporation and the Utility believe that the ultimate outcome of the litigation will not have a material adverse effect on their financial condition or results of operations.

Order Instituting Investigation into Holding Company Activities

On April 3, 2001, the CPUC issued an order instituting investigation into whether the California IOUs, including the Utility, have complied with past CPUC decisions, rules, orders, or applicable statutes authorizing their holding company formations and/or governing affiliate transactions. The order states that the CPUC will investigate (1) the utilities' transfer of money to their holding companies since deregulation of the electric industry commenced, including during times when their utility subsidiaries were experiencing financial difficulties, (2) the failure of the holding companies to financially assist the utilities when needed, (3) the transfer by the holding companies of assets to unregulated subsidiaries, and (4) the holding companies' action to "ringfence" their unregulated subsidiaries. The CPUC also will determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the ho lding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions, or recommend statutory changes to the California Legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate.

On January 9, 2002, the CPUC issued an interim decision and order interpreting the "first priority condition" adopted in the CPUC's holding company decision. This condition requires that the capital requirements of the utility, as determined to be necessary and prudent to meet the utility's obligation to serve or to operate the utility in a prudent and efficient manner, be given first priority by the board of directors of the holding company. In the interim order, the CPUC stated, "the first priority condition does not preclude the requirement that the holding company infuse all types of capital into their respective utility subsidiaries where necessary to fulfill the utility's obligation to serve." The three major California IOUs and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years' understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration, and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility's ability to fulfill its obligation to serve or to operate in a prudent and efficient manner. The utilities' applications for rehearing were denied on July 17, 2002.

In a related decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the interim decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision adopted on January 9, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum could decide expeditiously whether adoption of the Utility's original proposed plan of reorganization would violate the first priority condition. The utilities' applications for rehearing were denied on July 17, 2002.

The holding companies' petitions for review of these CPUC decisions are pending before the California Court of Appeals for the First Appellate District in San Francisco, California.

The proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding provides that on or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the proposed CPUC settlement agreement is final and nonappealable, the Utility and PG&E Corporation, on the one hand, and the CPUC, on the other, will execute full mutual releases and dismissals with prejudice of certain claims, actions, or regulatory proceedings, as specified in the settlement agreement, arising out of or related in any way to the California energy crisis or the implementation of AB 1890, including the CPUC's investigation into past holding company actions during the energy crisis (but only as to past actions, not prospective matters).

PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor PG&E Corporation, however, can predict what the outcome of the CPUC's investigation will be or whether the outcome will have a material adverse effect on their results of operations or financial condition.

William Ahern, et al. v. Pacific Gas and Electric Company

On February 27, 2002, a group of 25 ratepayers filed a complaint against the Utility at the CPUC demanding an immediate reduction of approximately $0.035 per kWh in allegedly excessive electric rates and a refund of alleged recent over-collections in electric revenue since September 1, 2001. The complaint claims that electric rate surcharges adopted in the first quarter of 2001 due to the high cost of wholesale power (surcharges that increased the average electric rate by $0.04 per kWh) became excessive later in 2001. The only alleged over-collection amount calculated in the complaint is approximately $400 million during the last quarter of 2001. On April 2, 2002, the Utility filed an answer, arguing that the complaint should be denied and dismissed immediately as an impermissible collateral action and on the basis that the alleged facts, even if assumed to be true, do not establish that currently authorized electric rates are not reasonable.

On May 10, 2002, the Utility filed a motion to dismiss the complaint. The CPUC has not yet issued a decision. However, in November 2002, the CPUC issued a decision jointly in this complaint case and in the rate stabilization proceedings modifying the restrictions on use of revenues generated by the surcharges to permit the revenues to be used for the purpose of securing or restoring the Utility's reasonable financial health, as determined by the CPUC. After the CPUC determines when the AB 1890 rate freeze ended, the CPUC will determine the extent and disposition of the Utility's under-collected costs, if any, remaining at the end of the rate freeze. If the CPUC determines that the Utility recovered revenues in excess of its transition costs or in excess of other permitted uses, the CPUC may require the Utility to refund such excess revenues. If the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially affected. Under the proposed CPU C settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would acknowledge and agree that the headroom, surcharge, and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund.

Income Tax Refund Litigation

NEGT, Inc. and its creditors have brought litigation against PG&E Corporation in NEGT, Inc.'s Chapter 11 proceeding pending in the U.S. Bankruptcy Court for the District of Maryland, asserting that NEGT, Inc. is entitled to be compensated for any tax savings achieved by PG&E Corporation as a result of the incorporation of the losses and deductions of NEGT, Inc. and its subsidiaries in PG&E Corporation's consolidated federal tax return under an alleged implied tax sharing agreement betwee n PG&E Corporation and NEGT, Inc. or otherwise. In May 2003, PG&E Corporation received a return of $533 million from the Internal Revenue Service for an overpayment of 2002 estimated federal income taxes resulting from losses and deductions incurred at PG&E Corporation, the Utility, and NEGT, Inc. and its subsidiaries, of which approximately $361.5 million was obtained by offsetting losses and deductions of NEGT, Inc. and its subsidiaries against income of PG&E Corporation and the Utility in PG&E Corporation's 2002 consolidated federal income tax return.

NEGT, Inc. and its creditors have asserted that it has a direct interest and is entitled to be paid approximately $414 million of the funds received by PG&E Corporation ($361.5 million achieved by the incorporation of losses and deductions of NEGT, Inc. or its subsidiaries and $53 million which NEGT, Inc. and its creditors allege was achieved by the incorporation of certain tax credits generated by NEGT, Inc.'s subsidiaries). NEGT, Inc. and its creditors allege, in part, that an implied tax sharing agreement exists between PG&E Corporation and NEGT, Inc. 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, Inc. for the incorporation of its or its subsidiaries' losses and deductions into PG&E Corporation's consolidated federal tax returns, as required under the Internal Revenue Code. The dispute will be resolved in the pending litigation . Consequently, until the dispute is resolved, PG&E Corporation is treating $361.5 million of the amount received by PG&E Corporation as restricted cash.

In October 2003, PG&E Corporation reached an agreement with NEGT, Inc. and its creditors under which (1) NEGT, Inc. and its creditors agreed to the dissolution of a temporary restraining order (TRO) that NEGT, Inc. previously had obtained, without prior notice to PG&E Corporation, that temporarily prohibited PG&E Corporation from using the $361.5 million in

funds, (2) NEGT, Inc. agreed to withdraw its motion for a preliminary injunction that would continue to prohibit PG&E Corporation from using such funds, and (3) PG&E Corporation agreed to provide NEGT, Inc. 10 business days advance notice before voluntarily allowing the cash balance in its institutional money market accounts to drop below $361.5 million or otherwise pledging such amount. On October 10, 2003, NEGT, Inc. withdrew its motion for a preliminary injunction and the Bankruptcy Court signed an order dissolving the TRO.

On November 7, 2003, an amended complaint was filed in the Bankruptcy Court by NEGT, Inc. as plaintiff, and its two creditors' committees, as plaintiffs-intervenors, against PG&E Corporation alleging additional causes of action arising out of or related to the filing by PG&E Corporation of its 2002 federal consolidated tax return, including claims for breach of contract, breach of fiduciary duty, violation of the automatic stay, turnover, an accounting, unjust enrichment, fraudulent transfer, constructive trust, equitable subordination, and indemnification. In addition, NEGT, Inc. and the creditors' committees seek a declaration that an implied tax sharing agreement exists between PG&E Corporation and NEGT, Inc. as well as injunctive relief prohibiting PG&E Corporation from taking certain tax positions on its consolidat ed 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, Inc.'s Board of Directors. The plaintiffs seek at least $414 million in damages, plus interest, costs of suit, and reasonable attorney's fees. In addition, plaintiffs seek punitive damages against PG&E Corporation and the former NEGT, Inc. directors for breach of fiduciary duty and seek punitive damages against PG&E Corporation for deceit.

The Bankruptcy Court has set a trial schedule in the litigation that currently calls for a trial to begin in July 2004; however, PG&E Corporation has filed a motion with the U.S. District Court for the District of Maryland (District Court) seeking withdrawal of the reference to the Bankruptcy Court, in part, on the grounds that the Bankruptcy Court cannot render final findings of fact or conclusions of law on the claims asserted in the litigation or conduct a jury trial without PG&E Corporation's consent. If the motion is successful, the litigation will be transferred to the District Court, which will preside over any trial in this litigation and will establish its own trial schedule.

PG&E Corporation does not expect that the outcome of this matter will have a material adverse effect on its results of operations. As described in Notes 1 and 4 above, effective July 8, 2003, PG&E Corporation no longer consolidates NEGT, Inc.'s financial results and is accounting for its investment in NEGT, Inc. using the cost method with all periods presented as discontinued operations.

NOTE 7: SEGMENT INFORMATION

PG&E Corporation has one reportable operating segment.

Segment information for the three- and nine-month periods ended September 30, 2003, and 2002, was as follows:

(in millions)

Utility

PG&E
Corporation,
Eliminations
and Other ⁽¹⁾

Total

Three months ended September 30, 2003

Operating revenues

$

3,103

$

-

$

3,103

Intersegment revenues

-

-

-

Total operating revenues

3,103

-

3,103

Income (Loss) from continuing operations ⁽²⁾

583

(75)

508

Net income (loss)⁽³⁾

583

(73)

510

Three months ended September 30, 2002

Operating revenues

2,947

-

2,947

Intersegment revenues

2

(2)

-

Total operating revenues

2,949

(2)

2,947

Income (Loss) from continuing operations ⁽²⁾

520

(41)

479

Net income (loss)⁽³⁾

520

(54)

466

Nine months ended September 30, 2003

Operating revenues

7,897

-

7,897

Intersegment revenues

3

(3)

-

Total operating revenues

7,900

(3)

7,897

Income (Loss) from continuing operations ⁽²⁾

844

(90)

754

Net income (loss)⁽³⁾

843

(460)

383

Nine months ended September 30, 2002

Operating revenues

8,108

-

8,108

Intersegment revenues

8

(8)

-

Total operating revenues

8,116

(8)

8,108

Income (Loss) from continuing operations ⁽²⁾

1,573

(41)

1,532

Net income (loss)⁽³⁾

1,573

(258)

1,315

Total assets at September 30, 2003

$

26,850

$

910

$

27,760

Total assets at September 30, 2002

$

24,942

$

11,693

$

36,635

⁽¹⁾
Includes PG&E Corporation, PG&E Ventures LLC, and elimination entries. PG&E Corporation's net income (loss) includes the results of NEGT, Inc.'s discontinued operations through July 7, 2003, and the elimination of $160 million for the nine-month period ended September 30, 2003, of deferred tax asset valuation reserves recorded at NEGT, Inc. PG&E Corporation believes it is more likely than not that it will be able to realize these deferred tax assets on a consolidated basis.

⁽²⁾
Corresponds to the Utility's Income Available for Common Stock excluding Cumulative Effect of a Change in Accounting Principle.

⁽³⁾
Corresponds to the Utility's Income Available for Common Stock.

NOTE 8: EMPLOYEE BENEFIT PLANS

On May 28, 2003, two of the Utility's unions ratified new contracts, which provide for, among other items, an increase in benefits provided under the Utility's defined benefit pension plan (Retirement Plan). As a result of the ratifications, the Utility remeasured the assets and liabilities of the Retirement Plan at May 28, 2003. In connection with the remeasurement, which reflected a reduction in the current discount rate from the Retirement Plan's previous actuarial valuation, the Utility recorded a minimum pension obligation of $478 million, the amount by which the accumulated benefit obligation exceeded the fair market value of plan assets, and reduced its pension asset from $887 million to $353 million. The Utility has previously recognized a regulatory liability for timing differences between recognition of pension costs in accordance with GAAP and ratemaking purposes. As a result of the remeasurement, the Utility has reduced this regulatory liability by $911 million. The remaining amount of $6 0 million, net of income tax benefit of $41 million, has been recorded as a component of shareholders' equity in OCI in the Consolidated Balance Sheets. The charge to OCI does not affect earnings or cash flow, and could be reversed in future periods if the fair value of plan assets exceeds the accumulated benefit obligation.

On September 23, 2003, the last of the Utility's three unions also ratified new contracts with an increase in benefits provided under the Retirement Plan. The Utility did not remeasure the assets and liabilities of the Retirement Plan at September 23, 2003, as there was no significant change to pension expense as a result of the plan change. The Utility's defined benefit pension plan currently exceeds the minimum funding requirements of the Employee Retirement Income Security Act of 1974.

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

OVERVIEW

PG&E Corporation is an energy-based holding company headquartered in San Francisco, California; its principal subsidiary, Pacific Gas and Electric Company (Utility), is an operating public utility engaged primarily in the business of providing electricity, natural gas distribution, and transmission services throughout most of Northern and Central California.

On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the federal Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (referred to as the Bankruptcy Court in this report's discussion of the Utility's Chapter 11 filing). Pursuant to Chapter 11 of the Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The factors that caused the Utility to take this action are discussed in this Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) and in Note 2 of the Notes to the Condensed Consolidated Financial Statements.

PG&E National Energy Group, Inc. (PG&E NEG), another subsidiary of PG&E Corporation, is a company with subsidiaries currently engaged in electricity generation and natural gas transmission in the United States of America. 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 (referred to as the Bankruptcy Court in this report's discussion of PG&E NEG's Chapter 11 filing). Pursuant to Chapter 11 of the Bankruptcy Code, PG&E NEG and those subsidiaries 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. The factors that caused PG&E NEG to take this action are discussed in this MD&A and in Note 4 of the Notes to the Consolidated Financial Statements. On October 3, 2003, the Bankruptcy C ourt authorized PG&E NEG to change its name to National Energy and Gas Transmission, Inc. (NEGT, Inc.). The change reflects NEGT, Inc.'s pending separation from PG&E Corporation. Consequently, for the remaining MD&A, any references to PG&E NEG, including its Chapter 11 filing and its plan of reorganization, will be referred to as NEGT, Inc.

The Consolidated Financial Statements of PG&E Corporation and of the Utility have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets, and repayment of liabilities in the ordinary course of business. However, as a result of the Utility's Chapter 11 filing as further discussed below, such realization of assets and liquidation of liabilities are subject to uncertainty.

This MD&A explains the general financial condition and the results of operations of PG&E Corporation and its subsidiaries, including:

Factors that affect each business;

A comparison of revenues and expenses and why they changed between periods;

The sources and uses of cash between periods; and

Other matters including commitments and contingencies that affect overall financial condition.

This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. The Consolidated Financial Statements of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Consolidated Financial Statements of the Utility reflect the accounts of the Utility and its wholly owned and controlled subsidiaries. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included herein. Further, this Quarterly Report should be read in conjunction with PG&E Corporation's and the Utility's Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in their combined 2002 Annual Report on Form 10-K, as amended.

Forward-Looking Statements and Risk Factors

This combined Quarterly Report on Form 10-Q, including this 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:

Outcome of the Utility's Chapter 11 Case. PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by the pace and outcome of the Utility's Chapter 11 case, which depends upon:

Whether the proposed settlement agreement with the staff of the California Public Utilities Commission (CPUC) that contemplates a new plan of reorganization (Settlement Plan) to supersede the competing plans of reorganization submitted in the Utility's Chapter 11 proceeding, and the rates, tariffs, and agreements that it contemplates, are approved by the CPUC after public hearings, the timing of such approval, and whether any such approvals are appealed and, if appealed, the timing and resolution of these appeals;

The outcome and the timing of the Bankruptcy Court's proceeding to confirm the Settlement Plan, whether the confirmation order is appealed and, if appealed, the timing and resolution of these appeals;

The impact of future ratemaking actions of the CPUC, including those actions that address the amount of the California Department of Water Resources' (DWR) revenue requirements that are allocated to the Utility for collection from the Utility's customers;

Whether the required credit ratings to implement the Settlement Plan are obtained;

Future equity or debt market conditions, future interest rates, future credit ratings, and other factors that may affect the ability to implement the Settlement Plan or affect the terms, amount, and value of the debt proposed to be issued under the Settlement Plan;

Whether a plan of reorganization containing substantially different terms than those contained in the Settlement Plan is confirmed; and

Whether a plan of reorganization is not confirmed for an extended period of time.

Operating Environment. The amount of operating income and cash flows the Utility may record may be influenced by the following:

Unanticipated changes in operating expenses and capital expenditures;

The level and volatility of wholesale electricity and natural gas prices and the Utility's ability to manage and respond to this volatility successfully;

Weather, storms, earthquakes, fires, other natural disasters, explosions, accidents, mechanical breakdowns, and other events or perils 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;

The Utility's ability to manage the net open position over time, which can be affected by whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR;

The operation and decommissioning of the Utility's Diablo Canyon nuclear power plant, which expose the Utility to potentially significant environmental and capital expenditure risks, 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;

Significant changes in the Utility's relationship with its employees, including the retirement of existing employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur;

Acts of terrorism; and

Actions of credit rating agencies.

Legislative and Regulatory Environment. PG&E Corporation's and the Utility's business may be impacted by:

The possibility that the proposed settlement agreement is not approved by the CPUC or is modified or invalidated on appeal, or if the Settlement Plan is not confirmed or implemented, the timing and impact of the end of the retail electricity rate freeze, the structure of post-rate freeze ratemaking, and whether the Utility is required to refund previously collected revenues to ratepayers;

Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, U.S. Congress, the CPUC, and the Federal Energy Regulatory Commission (FERC), 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;

How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the holding company;

Future regulatory proceedings related to whether the Utility has complied with all applicable rules, tariffs, and orders, and the extent to which a finding of non-compliance could result in customer refunds, penalties, or other non-recoverable expenses; and

The effect of compliance with existing and future environmental laws, regulations, and policies, including those addressing global climate change.

Pending Litigation and Regulatory Proceedings. PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by the outcome of pending litigation and regulatory proceedings, including proceedings related to the allocation of the DWR's revenue requirements among the three California investor-owned utilities (IOUs) for future or prior periods, the timing and impact of the end of the retail electric rate freeze, the structure of post-rate freeze ratemaking, whether the Utility is required to refund previously collected revenues to ratepayers, and whether the proposed settlements in the Utility's 2003 General Rate Case (GRC) proceeding are approved by the CPUC.

Competition. PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by:

Increased competition as a result of the takeover by condemnation or municipalization of the Utility's distribution assets, self-generation by its customers and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load, and additional barriers to cost recovery;

The extent to which the cities and counties in the Utility's service territory become community choice aggregators and the extent to which the Utility's distribution customers can switch between purchasing electricity from the Utility or from alternate energy service providers as direct access customers; and

Changes in the level of the direct access customer cost responsibility surcharge, as well as other surcharges related to direct access, and changes to the current suspension of direct access.

Accounting and Risk Management. PG&E Corporation's and the Utility's future results of operations and financial conditions may be affected by new accounting pronouncements, including significant changes in accounting policies material to PG&E Corporation or the Utility.

As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from historical results or outcomes currently sought or expected.

LIQUIDITY AND FINANCIAL RESOURCES

Utility

On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code due in part to its inability, during the California energy crisis, to recover its procurement costs from customers in its rates. PG&E Corporation and the Utility have incurred, and will continue to incur throughout the reorganization process, legal, accounting, trustee, and other costs associated with the implementation of the proposed CPUC settlement agreement.

While the Utility is in Chapter 11 proceedings, the Utility is not allowed to pay liabilities incurred before it filed for its Chapter 11 petition without permission from the Bankruptcy Court. Additionally, the Utility:

Does not have access to external funding from capital markets;

Is in default under its credit facilities, commercial paper, floating rate notes, senior notes, pollution control loan agreements, mortgage bonds, and medium-term notes as a result of its failure to pay certain of its obligations. However, the event of default under each debt obligation has been stayed in accordance with the Utility's Chapter 11 proceedings; and

Has been making capital investments (investments in property, plant and equipment) out of its cash on hand under the supervision of the Bankruptcy Court. The Utility anticipates that it will be able to continue making such necessary capital investments in the future, subject to Bankruptcy Court approval.

Since filing for Chapter 11, the Utility has received permission from the Bankruptcy Court to make payments on (1) pre- and post-petition interest on certain claims, (2) pre-petition amounts payable to qualifying facilities (QFs) and certain other vendors, and (3) matured pre-petition secured debt.

Also, the Utility has been, and will continue, accruing interest on its pre-petition liabilities at the required rates included in the Utility's proposed settlement agreement. However, due to the uncertainty of the ultimate outcome of the Utility's Chapter 11 proceedings, the Utility is not able to estimate the amount of interest that will be paid in 2003 and beyond.

Competing Plans of Reorganization

The Proposed CPUC Settlement Agreement

The principal terms of the proposed CPUC settlement agreement are as follows:

Regulatory Asset

The CPUC would agree to establish a $2.2 billion after-tax regulatory asset (Regulatory Asset), which equates to an approximately $3.7 billion pre-tax regulatory asset, as a new, separate and additional part of the Utility's rate base that would be amortized on a ''mortgage-style'' basis over nine years beginning January 1, 2004. The Regulatory Asset would be fully amortized by the end of 2012. The CPUC also would agree to authorize the Utility to establish a tax tracking account, to be used if the Utility must pay income tax on the Regulatory Asset before it is fully amortized, to record the difference between taxes on the Regulatory Asset plus interest imposed by federal or state tax authorities for earlier recognition, and taxes that would have been incurred on account of the Regulatory Asset had it been taxed during the amortization period. The tax tracking account will earn the authorized rate of return and be amortized into rates over the longer of the remaining life of the Regulatory Asset or f ive years.

The net after-tax amount of any refunds, claim offsets, or other credits from generators or other energy suppliers relating to the Utility's PX, ISO, QF, or energy service provider costs during the California energy crisis that the Utility realizes in cash or by offset of creditor claims in its Chapter 11 case will reduce the outstanding balance of the Regulatory Asset, dollar for dollar. Similarly, the net after-tax amounts received in cash by the Utility for electricity claims under the master settlement agreement with El Paso Corporation and certain of its affiliates (El Paso) also would cause a reduction in the outstanding balance and the remaining amortization of the Regulatory Asset.

The Regulatory Asset would earn a return on equity (ROE) of at least 11.22 percent annually for its term and, after the equity component of the Utility's capital structure reaches 52.00 percent, the authorized equity component of the Regulatory Asset would be no less than 52.00 percent for the remaining term of the Regulatory Asset. The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

Ratemaking Matters

The CPUC would agree that the Utility's rate base for its utility retained generation (URG) would be deemed just and reasonable and would not be subject to modification, adjustment, or reduction, except as necessary to reflect capital expenditures and any change in authorized depreciation. This would result in the recording of an additional after-tax regulatory asset of approximately $0.8 billion (or approximately $1.3 billion pre-tax). The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

The CPUC would timely act upon the Utility's applications to collect in rates prudently incurred costs (including return of and return on) of any new and reasonable investment in utility plant and assets. The CPUC also would promptly adjust the Utility's rates consistent with the California legislation (Assembly Bill (AB) 57 and Senate Bill (SB) 1976) and the CPUC's 2002 agreement with the DWR regarding the establishment of the DWR's revenue requirements to ensure that the Utility's collection of certain charges to service existing rate reduction bonds, regulatory asset amortization and return, and base revenue requirements (e.g., electricity and natural gas distribution, the Utility's rate base for its electricity generation, gas commodity procurement, existing QF contract costs, and associated return) are not impaired. The CPUC would not discriminate against the Utility because of the Utility's Chapter 11 case, the Utility's pending federal lawsuit against the CPUC Commissioners to recover its previo usly incurred costs of providing electric service from ratepayers under the federal filed rate doctrine, the proposed CPUC settlement agreement, the Regulatory Asset, or any other matters addressed in or resolved by the proposed CPUC settlement agreement.

The CPUC would maintain the Utility's retail electric rates at current levels through December 31, 2003. As of January 1, 2004, the CPUC may adjust the Utility's retail electric rates prospectively consistent with the proposed CPUC settlement agreement, the Settlement Plan, the order confirming the Settlement Plan, and California law. The proposed CPUC settlement agreement includes a statement of intent that under the Settlement Plan, retail electricity rates would be reduced in January 2004, with further reductions expected thereafter.

The CPUC would set the Utility's capital structure and authorized ROE in the Utility's annual cost of capital proceedings in its usual manner. However, from January 1, 2004, until S&P has issued a long-term issuer credit rating for the Utility of at least A- or Moody's has issued an issuer credit rating for the Utility of at least A3, the authorized ROE would be no less than 11.22 percent per year and the authorized equity ratio for ratemaking purposes would be no less than 52.00 percent, except that for 2004 and 2005, the authorized equity ratio would equal the greater of the proportion of equity in the forecast of its average capital structure for calendar years 2004 and 2005 filed in the Utility's cost of capital proceeding and 48.60 percent.

The CPUC also would agree to act promptly on certain of the Utility's pending ratemaking proceedings, including the Utility's pending 2003 GRC. The outcome of these proceedings may result in the establishment of additional regulatory assets on the Utility's Consolidated Balance Sheets.

California Department of Water Resources Contracts

The Utility would agree to accept an assignment of, or to assume legal and financial responsibility for, the DWR contracts that have been allocated to the Utility, but only if:

After assignment or assumption of the DWR contracts, the Utility receives a long-term issuer credit rating of at least A from S&P and A2 from Moody's;

The CPUC first has made a finding that the DWR contracts being assumed are just and reasonable; and

The CPUC has acted to ensure that the Utility receives full and timely recovery in its retail electricity rates of all costs of the DWR contracts without further review.

Headroom

The CPUC would agree and acknowledge that the headroom, surcharge, and base revenues accrued or collected by the Utility through and including December 31, 2003, are the property of the Utility's Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility's Chapter 11 proceeding, have been included in the Utility's retail electric rates consistent with state and federal law, and are not subject to refund. The proposed CPUC settlement notes that it is in the public interest to restore the Utility's financial health and to allow the Utility to recover, over a reasonable time, prior uncollected costs. For financial reporting purposes, these amounts that restore the Utility's financial health and recover previously written-off under-collected costs are referred to as headroom. The proposed CPUC settlement agreement defines headroom as the Utility's total net after-tax income reported under accounting principles generally accepted in the United States of Amer ica (GAAP), less earnings from operations, (as has been historically defined by PG&E Corporation in its earnings press release, a non-GAAP financial measure), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided the calculation will reflect the outcome of the Utility's 2003 GRC. The proposed CPUC settlement agreement provides that if headroom accrued by the Utility during 2003 is greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom is less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in future rates.

Dismissal of Filed Rate Case, Other Litigation, and Regulatory Proceedings

On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement is no longer subject to appeal, the Utility would dismiss with prejudice its case against the CPUC Commissioners asserting the "filed rate doctrine," withdraw the original plan of reorganization, and dismiss other pending proceedings. In exchange, on or before January 1, 2004, the CPUC would establish and authorize the collection of the Regulatory Asset and the Utility's rate base for its electricity generation, and on or as soon as practicable after the effective date, resolve phase 2 of the pending Annual Transition Cost Proceeding in which the CPUC is reviewing the reasonableness of the Utility's procurement costs incurred during the energy crisis with no adverse impact on the Utility's cost recovery as filed.

On or as soon as practicable after the later of the effective date of the Settlement Plan or the date the CPUC decision approving the settlement agreement is no longer subject to appeal, PG&E Corporation, the Utility, and the CPUC would execute mutual releases and dismissals with prejudice of specified claims, actions, or regulatory proceedings arising out of or related in any way to the energy crisis or the implementation of AB 1890, including the CPUC's investigation into past holding company actions during the California energy crisis (but only as to past actions, not prospective matters).

Environmental Measures

The Utility would agree to implement three environmental enhancement measures:

The Utility would encumber with conservation easements or donate approximately 140,000 acres of land to public agencies or non-profit conservation organizations;

The Utility would establish a California non-profit corporation to oversee the environmental enhancements associated with these lands and fund it with $70 million in cash over 10 years, although the Utility would be entitled to recover these payments in rates; and

The Utility would create a non-profit corporation funded with $15 million payable by the Utility over five years dedicated to support research and investment in clean energy technology, primarily in the Utility's service territory.

Waiver of Sovereign Immunity

Term and Enforceability

Fees and Expenses

Conditions of the Effectiveness of the Settlement Plan

The Settlement Plan provides that it would not be confirmed by the Bankruptcy Court unless and until the following conditions are satisfied or waived:

The Bankruptcy Court enters an order or orders:

Approving the Settlement Plan, authorizing the Utility to execute, enter into, and deliver the Settlement Plan, and to execute, implement, and take all actions necessary or appropriate to give effect to the transactions contemplated by the Settlement Plan;

Approving and authorizing the execution of, and finding reasonable the terms and conditions of, the proposed CPUC settlement agreement; and

The Confirmation Order is, in form and substance, reasonably satisfactory to PG&E Corporation, the Utility, the OCC, and the CPUC and specifically includes certain matters.

The Settlement Plan also provides that it would not become effective unless and until the following conditions are satisfied or waived:

The effective date occurs on or before March 31, 2004;

All actions, documents, and agreements necessary to implement the Settlement Plan are effected or executed;

PG&E Corporation and the Utility have received all authorizations, consents, regulatory approvals, rulings, letters, no-action letters, opinions, or documents that they deem necessary to implement the Settlement Plan;

The Settlement Plan has not been modified in a material way since the date of confirmation;

The Utility has consummated the sale of the debt securities contemplated by the Settlement Plan;

S&P has issued a long-term issuer credit rating for the Utility of not less than BBB- and Moody's has issued an issuer rating for the Utility of not less than Baa3;

S&P and Moody's have issued credit ratings for the debt securities to be offered by the Utility of not less than BBB- and Baa3, respectively;

The CPUC has given final nonappealable approval of the proposed CPUC settlement agreement on behalf of the CPUC;

Each of the parties to the proposed CPUC settlement agreement has executed and delivered the settlement agreement;

The CPUC has given final nonappealable approval for all of the financings, securities, and accounts receivable programs provided for in the Settlement Plan; and

The CPUC has given final nonappealable approval for all rates, tariffs, and agreements necessary to implement the Settlement Plan.

The last six conditions cannot be waived, except that PG&E Corporation and the Utility can waive the right to the finality provisions regarding CPUC approvals.

PG&E Corporation and the Utility are unable to predict whether and when the proposed CPUC settlement agreement will become effective or whether the Settlement Plan will be confirmed or implemented. If the Settlement Plan is not confirmed, or if the CPUC does not approve the proposed CPUC settlement agreement and related rates, or if the CPUC takes actions materially inconsistent with the proposed CPUC settlement agreement in pending regulatory proceedings associated with the recovery of transition costs and surcharge revenues, or the allocation of DWR electricity to customers of IOUs, as detailed in Note 6 of the Notes to the Consolidated Financial Statements, then the Utility's financial condition and results of operations could be materially adversely affected.

NEGT, Inc.

On July 8, 2003, NEGT, Inc. filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code. In addition, on July 8, 2003, NEGT Energy Trading Holdings Corporation (NEGT ET), formerly known as PG&E Energy Trading Holdings Corporation, PG&E Energy Trading - Power, L.P., and PG&E Energy Trading - Gas Corporation (collectively, the ET Companies) voluntarily filed petitions for protection under Chapter 11 of the Bankruptcy Code. USGen New England, Inc. (USGenNE) also filed its own petition for Chapter 11 relief. On July 29, 2003, two other subsidiaries, Quantum Ventures and Energy Services Ventures, Inc., formerly known as PG&E Energy Services Ventures, Inc., each filed voluntary Chapter 11 petitions. The Chapter 11 case of USGenNE is being administered separately from those of NEGT, Inc. and the other subsidiaries.

Pursuant to Chapter 11 of the Bankruptcy Code, NEGT, Inc. and these subsidiaries retain control of their assets and are authorized to operate their businesses as debtors-in-possession while they are subject to the jurisdiction of the Bankruptcy Court. Additionally, on July 8, 2003, NEGT, Inc. filed a plan of reorganization after reaching an agreement in principle as to the plan's key terms with an informal group of creditors that included major creditors, several bondholders, and agents under certain unsecured credit facilities acting in their individual capacities. NEGT, Inc.'s proposed plan of reorganization would not restructure the indebtedness of any of the debtors, other than NEGT, Inc. If NEGT, Inc.'s plan of reorganization is confirmed by the Bankruptcy Court and implemented, PG&E Corporation no longer would have any equity interest in NEGT, Inc. or any of its subsidiaries. It is anticipated that the Chapter 11 plans for USGenNE and the ET Companies will be filed at a later date.

As a result of NEGT, Inc.'s Chapter 11 filing on July 8, 2003 and the proposed loss of equity ownership provided for in NEGT, Inc.'s plan of reorganization, PG&E Corporation considers its investment in NEGT, Inc. to be an abandoned asset and has accounted for NEGT, Inc. as a discontinued operation in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). Under the provisions of SFAS No. 144, the operating results of NEGT, Inc. and its subsidiaries are reported as discontinued operations in the Consolidated Statements of Income for all periods reported. In addition, all prior period assets and liabilities of NEGT, Inc., shown for comparative purposes, are classified as discontinued operations in the Consolidated Statements of Income for all periods reported. As of July 8, 2003, PG&E Corporation accounts for NEGT, Inc. using the cost method. As NEGT, Inc. is no longer consolidated by PG&E Corpor ation, the accompanying September 30, 2003, Consolidated Balance Sheet of PG&E Corporation does not reflect the separate assets and liabilities of NEGT, Inc.; rather, a liability is reflected, which represents the losses recognized by PG&E Corporation in excess of its investment in and advances to NEGT, Inc. PG&E Corporation's investment in NEGT, Inc. will not be affected by changes in NEGT, Inc.'s future financial results, other than (1) investments in or dividends from NEGT, Inc., or (2) income taxes that PG&E Corporation may be required to pay if the Internal Revenue Service disallows certain deductions or tax credits attributable to NEGT, Inc. and its subsidiaries for past tax years that are incorporated into PG&E Corporation's consolidated tax returns.

Upon implementation of NEGT, Inc.'s plan of reorganization that eliminates PG&E Corporation's equity in NEGT, Inc., PG&E Corporation will reverse its investment in NEGT, Inc. and the amounts included in accumulated other comprehensive income (OCI) and deferred taxes, and, as a result, recognize a one-time net non-cash gain to earnings from discontinued operations.

RESULTS OF OPERATIONS

In this section, PG&E Corporation discusses earnings and the factors affecting them. The table below details certain items from the accompanying Consolidated Statements of Income for the three- and nine-month periods ended September 30, 2003, and 2002.

(in millions)		Utility		PG&E Corporation, Eliminations and Other ⁽¹⁾		Total


Three months ended September 30, 2003
Operating revenues		$	3,103	$	-	$	3,103
Operating expenses			1,908		22	1,930

Operating income (loss)		$	1,195	$	(22)	1,173



Interest income						15
Interest expense						(342)
Other income (expenses), net						(5)

Income before income taxes						841
Income taxes						333

Income from continuing operations						508

Net income						$	510




Three months ended September 30, 2002 ⁽²⁾
Operating revenues		$	2,949	$	(2)	$	2,947
Operating expenses			1,890		(12)	1,878

Operating income		$	1,059	$	10	1,069



Interest income						20
Interest expense						(371)
Other income, net						60

Income before income taxes						778
Income taxes						299

Income from continuing operations						479

Net income						$	466




Nine months ended September 30, 2003 ⁽²⁾
Operating revenues		$	7,900	$	(3)	$	7,897
Operating expenses			5,901		(30)	5,871

Operating income		$	1,999	$	27	2,026



Interest income						49
Interest expense						(857)
Other income (expenses), net						(10)

Income before income taxes						1,208
Income taxes						454

Income from continuing operations						754

Net income						$	383




Nine months ended September 30, 2002 ⁽²⁾
Operating revenues		$	8,116	$	(8)	$	8,108
Operating expenses			4,750		(54)	4,696

Operating income		$	3,366	$	46	3,412



Interest income						60
Interest expense						(971)
Other income, net						59

Income before income taxes						2,560
Income taxes						1,028

Income from continuing operations						1,532

Net income						$	1,315




⁽¹⁾	PG&E Corporation eliminates all inter-segment transactions in consolidation.
⁽²⁾	Prior period amounts of NEGT, Inc. have been reclassified to discontinued operations.

PG&E Corporation - Consolidated

Overall Results

PG&E Corporation's net income for the three months ended September 30, 2003, was $510 million compared to $466 million for the same period in 2002. PG&E Corporation's net income for the nine months ended September 30, 2003, was $383 million compared to $1,315 million for the same period in 2002.

The significant increases (decreases) in income from continuing operations for the three- and nine-month periods ended September 30, 2003 compared to the same periods in 2002, are summarized in the table below:

			Three months ended		Nine months ended
(in millions)			September 30		September 30

PG&E Corporation
	Interest expense	$	44	$	33

Utility
	Electric revenues		41		(631)
	Natural gas revenues		113		415
	Cost of electricity		(124)		(841)
	Cost of natural gas		(114)		(407)
	Operating and maintenance expenses		191		174
	Depreciation, amortization and decommissioning		4		(36)
	Reorganization professional fees and expenses		25		(41)
	Interest and other income, net		(5)		(2)
	Interest expense		(16)		86

Interest Expense

PG&E Corporation's interest expense decreased for both the three months and nine months ended September 30, 2003, compared to the same periods in 2002. The decrease in interest expense is primarily due to the reduction in interest rates and outstanding long-term debt balances during 2003, compared to 2002. During the third quarter of 2002, PG&E Corporation recognized a write-off of approximately $68 million of deferred charges and unamortized loan discounts in connection with the repayment and modification of PG&E Corporation's amended and restated loan agreement. During the third quarter of 2003, PG&E Corporation recognized a write-off of approximately $89 million of unamortized loan fees, loan discount, and prepayment fees associated with the repayment in July 2003 of approximately $735 million of principal under PG&E Corporation's existing credit agreement.

Dividends

PG&E Corporation did not declare any dividends in the first nine months of 2003 or 2002. PG&E Corporation was prohibited from paying dividends under the terms of its $720 million credit agreement with Lehman Commercial Paper, Inc. until the loans were repaid. On July 2, 2003, amounts outstanding under the credit agreement were repaid through the issuance of $600 million of new 6⅞ percent Senior Secured Notes (Notes). (See Note 3 of the Notes to the Consolidated Financial Statements for further details.) The Note indenture prohibits PG&E Corporation from declaring or paying dividends unless, as specified in the indenture, it has either met certain financial criteria, and no default is outstanding under the indenture or would result from the payment of such dividends or a specified exception applies. These specified exceptions include circumstances in which: (1) PG&E Corporation achieves an investment grade credit rating, or (2) following the implementation of the Utility's Settle ment Plan, PG&E Corporation pays any dividend from the proceeds of cash distributions to PG&E Corporation from the Utility. Certain of these exceptions also include the requirement that no default is outstanding under the indenture or would result from the payment of such dividends.

NEGT, Inc. has not declared a dividend since reorganization in 2002 and PG&E Corporation will not receive any distribution under the terms of NEGT, Inc.'s plan of reorganization.

While in Chapter 11, the Utility is not allowed to pay dividends without Bankruptcy Court approval. In addition, the proposed CPUC settlement agreement and Settlement Plan would prohibit the Utility from paying dividends to PG&E Corporation before July 1, 2004. Assuming the proposed CPUC settlement agreement is approved and the Settlement Plan implemented, PG&E Corporation does not anticipate paying a dividend until the later part of 2005.

Historically, in determining whether to, and at what level to, declare dividends, PG&E Corporation's Board of Directors 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.

Utility

Electric Revenues

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

Three months ended

Nine months ended

September 30,

September 30,

(in millions)

2003

2002

2003

2002

Residential

$

996

$

1,046

$

2,740

$

2,805

Commercial

1,292

1,468

3,208

3,464

Industrial

381

448

1,037

1,153

Agricultural

204

222

402

443

Miscellaneous

44

112

330

335

Direct access credits

(102)

(95)

(252)

(285)

DWR pass-through revenue

(291)

(718)

(1,642)

(1,461)

Total electric operating revenues

$

2,524

$

2,483

$

5,823

$

6,454

Electric operating revenues increased $41 million, or 1.7 percent, for the three months ended September 30, 2003, compared to the same period in 2002 primarily due to the following:

Electric sales volume increased by 4 percent for the three months ended September 30, 2003, compared to the same period in 2002, primarily due to warmer weather in the third quarter of 2003. The increase in electric revenues, as a result of the increase in electric sales volume, was offset by a one-time bill credit associated with the reduction in the 2003 DWR revenue requirement discussed below.

Amounts recorded as pass-through revenue to the DWR decreased by $427 million for the three months ended September 30, 2003, compared to the same period in 2002. The Utility passes revenue through to the DWR for electricity provided by the DWR to the Utility's customers. The decrease was primarily due to (1) a reduction in the 2003 DWR revenue requirement, and (2) an adjustment recorded in the third quarter of 2002 to reflect changes to the methodology used to calculate DWR pass-through revenues. These decreases were partially offset by an additional bond charge passed through to the DWR, which began in November 2002, and an increase in the Utility's DWR power charge remittance rate effective January 1, 2003.

The reduction in the DWR's 2003 revenue requirement was due primarily to a September 2003 CPUC decision that reduced the DWR's approved revenue requirement for 2003. This reduction was offset by a corresponding reduction in electric revenues for each customer class, as the decision also required the Utility to pass the benefit of the revenue requirement reduction on to its customers through a separate one-time bill credit. (See the "Regulatory Matters" section of this MD&A.)

From January 2001 through December 2002, the DWR was responsible for procuring electricity required to cover the Utility's net open position (the amount of electricity needed by retail customers that cannot be met by Utility-owned generation or existing electricity contracts). The Utility resumed purchasing electricity on the open market in January 2003, but still relies on electricity provided by DWR contracts to service a significant portion of its total load. Revenues collected on behalf of the DWR and the DWR's related costs are not included in the Utility's Consolidated Statements of Income, reflecting the Utility's role as a billing and collection agent, for which the Utility collects no fees, for the DWR's sales to the Utility's customers.

Electric operating revenues decreased $631 million, or 9.8 percent, for the nine months ended September 30, 2003, compared to the same period in 2002 primarily due to the following:

Amounts recorded as pass-through revenues to the DWR increased by $181 million for the nine months ended September 30, 2003, compared to the same period in 2002. The Utility passes revenue through to the DWR for electricity provided by the DWR to the Utility's customers. The increase in DWR pass-through revenues was primarily due to (1) an additional bond charge passed through to the DWR, which began in November 2002, (2) an increase in volume supplied by the DWR, and (3) an increase in the Utility's DWR power charge remittance rate effective January 1, 2003. The increase in DWR pass-through revenues was partially offset by the reduction in the 2003 DWR revenue requirement described above.

The average electric sales price decreased during 2003 due to a May 2002 CPUC decision that increased baseline quantity allowances. An increase to a customer's baseline quantity allowance increases the amount of the customer's monthly usage that is covered under the lowest possible rate and is exempt from the three-cent surcharge.

The decrease in electric revenues was partially offset by an increase in electric sales volume due to warmer weather in 2003 and an increase in the amount recorded in 2003 to include an estimate for electricity delivered to customers whose bills have been delayed.

Cost of Electricity

The following table shows a breakdown of the Utility's cost of electricity (which includes the cost of fuel used by the Utility owned generation facilities and electricity purchase costs) and the total amount and average cost of purchased power, excluding in each case both the cost and volume of electricity provided by the DWR to the Utility's customers:

	Three months ended September 30,				Nine months ended September 30,

(in millions)	2003		2002		2003		2002


Cost of purchased power	$	710	$	529	$	1,856	$	1,415
Proceeds from surplus sales allocated to the Utility	(63)		-		(197)		-
Fuel used in own generation	32		26		76		74
Adjustment to purchased power accruals	-		-		-		(595)

Total Cost of Electricity	$	679	$	555	$	1,735	$	894



Average cost of purchased power per kWh	$	0.071	$	0.075	$	0.074	$	0.074

Total purchased power (GWh)	9,982		7,080		25,230		19,219

The Utility's cost of electricity increased $124 million, or 22.3 percent, for the three months ended September 30, 2003, and $841 million, or 94.1 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. Increases in the cost of electricity for both periods were primarily due to an increase in the total volume of electricity purchased. In the first quarter of 2003, the Utility began buying and selling electricity on the open market in accordance with its CPUC-approved electricity procurement plan (see the "Regulatory Matters" section of this MD&A). Based on the CPUC requirement to perform least-cost dispatch, the Utility is required to dispatch all of the generating resources within its portfolio, including DWR contracts assigned to the Utility to administer, in the most cost-effective way. This requirement in certain cases requires the Utility to schedule more electricity than is required to meet its retail load and to sell this additional electricity on the o pen market. This typically occurs when the expected sales proceeds exceed the variable costs to operate a resource or call on a contract.

The increase in total costs was partially offset by proceeds from surplus electricity sales. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.

Increases in the cost of electricity for the nine months ended September 30, 2003, were also due to a net $595 million reduction to the cost of electricity recorded in March 2002 as a result of FERC and CPUC decisions, which allowed the Utility to reverse previously accrued Independent System Operator (ISO) charges and to adjust for the amount previously accrued as payable to the DWR for its 2001 revenue requirement.

Natural Gas Revenues

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

	Three months ended September 30,				Nine months ended September 30,

(in millions)	2003		2002		2003		2002


Bundled gas revenues	$	355	$	237	$	1,840	$	1,382
Transportation service-only revenues	76		87		209		247
Other	148		142		28		33

Total Natural Gas Revenues	$	579	$	466	$	2,077	$	1,662



Average bundled revenue per Mcf of natural gas sold	$	8.88	$	5.64	$	8.89	$	6.40

Total bundled gas sales (in millions of Mcf)		40		42		207		216

Bundled natural gas revenues increased $118 million, or 49.8 percent, for the three months ended September 30, 2003, and $458 million, or 33.1 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. Increases for both periods were primarily a result of a higher average cost of natural gas, which was passed along to customers through higher rates. The average bundled revenue per thousand cubic feet (Mcf) of natural gas sold increased $3.24, or 57.4 percent, for the three months ended September 30, 2003, and $2.49, or 38.9 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002.

Transportation service-only revenues decreased by $11 million, or 12.6 percent, for the three months ended September 30, 2003, and $38 million, or 15.4 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. These decreases were primarily due to a decrease in demand for natural gas transportation services by natural gas-fired electric generators in California.

Other natural gas revenues primarily include balancing account revenues. These revenues increased $6 million, or 4.2 percent, for the three months ended September 30, 2003, and decreased $5 million, or 15.2 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. The Utility tracks natural gas revenues and costs in natural gas balancing accounts. Over-collections and under-collections are deferred until they are refunded to or received from the Utility's customers through rate adjustments.

Cost of Natural Gas

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

	Three months ended September 30,				Nine months ended September 30,

(in millions)	2003		2002		2003		2002


Cost of natural gas sold	$	203	$	98	$	941	$	560
Cost of natural gas transportation	30		21		98		72

Total Cost of Natural Gas	$	233	$	119	$	1,039	$	632



Average cost per Mcf of natural gas purchased	$	5.08	$	2.33	$	4.55	$	2.59

Total natural gas purchased (in millions of Mcf)		40		42		207		216

The Utility's cost of natural gas sold increased $105 million for the three months ended September 30, 2003, and $381 million for the nine months ended September 30, 2003, compared to the same periods in 2002. Increases for both periods were primarily due to an increase in the average cost of natural gas purchased of $2.75 per Mcf and $1.96 per Mcf for the three- and nine-month periods ended September 30, 2003, compared to the same periods in 2002.

The Utility's cost to transport natural gas to its service area increased by $9 million, or 42.9 percent, for the three months ended September 30, 2003, and $26 million, or 36.1 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. These increases were primarily due to new pipeline transportation charges paid to the El Paso Natural Gas Company pipeline. The Utility, along with other California utilities, was ordered by the CPUC in July 2002 to enter into long-term contracts to purchase firm transportation services on the El Paso Natural Gas Company pipeline.

Operating and Maintenance

The Utility's operating and maintenance expenses decreased $191 million, or 22.2 percent, for the three months ended September 30, 2003, and $174 million, or 7.7 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. Decreases for both periods were primarily due to the following:

The recording of regulatory liabilities for surcharge revenues during 2002, with no comparable amounts in 2003. In January 2001, the CPUC increased electric rates by various surcharges and restricted the use of these surcharge revenues to "ongoing procurement costs" and "future power purchases." In November and December 2002, the CPUC authorized the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. As a result, the Utility reversed its existing regulatory liabilities related to the surcharge revenues during the fourth quarter of 2002 and no longer reserved these amounts, resulting in a decrease in operating and maintenance expenses in 2003. (See the "Regulatory Matters" section of this MD&A.)

A net increase in deferred electric transmission-related costs compared to 2002. Electric transmission-related costs are included in the cost of electricity and consist primarily of reliability must run charges from the ISO. To the extent the Utility does not receive revenues sufficient to recover electric transmission-related costs, the costs are deferred through a reduction of operating and maintenance expense until recovered through future rates.

The decrease in operating and maintenance expenses was partially offset by higher recorded costs for environmental matters and increases in employee-related expenses, public purpose programs spending, customer-related costs, and maintenance expenses incurred during the scheduled refueling outage at the Diablo Canyon Power Plant in the first quarter of 2003.

Depreciation, Amortization, and Decommissioning

Depreciation, amortization, and decommissioning expenses decreased $4 million, or 1.3 percent, for the three months ended September 30, 2003, and increased $36 million, or 4.1 percent, for the nine months ended September 30, 2003, as compared to the same periods in 2002. The increase in depreciation expense for the nine months ended September 30, 2003, was due primarily to an overall increase in the Utility's plant assets and an increase of $12 million in amortization of the rate reduction bond regulatory asset, which began at the end of January 2002.

Reorganization Fees and Expenses

In accordance with the American Institute of Certified Public Accountants' Statement of Position (SOP) 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code" (SOP 90-7), the Utility reports reorganization fees and expenses separately on its Consolidated Statements of Income. Such costs primarily include professional fees for services in connection with the Utility's Chapter 11 proceedings and totaled $16 million for the three months ended September 30, 2003, and $116 million for the nine months ended September 30, 2003.

Interest Income

In accordance with SOP 90-7, the Utility reports reorganization interest income separately on its Consolidated Statements of Income. Such income primarily includes interest earned on cash accumulated during the Utility's Chapter 11 proceedings. Interest income, which includes reorganization interest income, decreased $7 million, or 38.9 percent, for the three months ended September 30, 2003, and $17 million, or 28.8 percent, for the nine months ended September 30, 2003, compared to the same periods in 2002. Decreases for both periods were due primarily to lower average interest rates earned on the Utility's short-term investments.

Interest Expense

The Utility's interest expense increased $16 million, or 7.2 percent, for the three months ended September 30, 2003, compared to the same period in 2002 primarily due to the recording of interest payable to the DWR. The interest was to compensate the DWR for prior underpayments resulting from ambiguities in the formula that determined the payment. These ambiguities were resolved by the CPUC in a decision issued in September 2003. (See the "Regulatory Matters" section of this MD&A.)

The Utility's interest expense decreased $86 million, or 11.2 percent, for the nine months ended September 30, 2003, compared to the same period in 2002 primarily due to a reduction of interest on rate reduction bonds and a lower level of unpaid debts accruing interest. The decrease was partially offset by the recording of interest payable to the DWR described above.

Dividends

While in Chapter 11, the Utility is not allowed to pay dividends without Bankruptcy Court approval. Under the proposed CPUC settlement agreement and the Settlement Plan, there would be no restriction on the ability of the Utility to declare and pay dividends or repurchase common stock, other than the capital structure and stand-alone dividend conditions contained in prior CPUC holding company decisions; provided, however, that the Utility would agree that it would not pay dividends on its common stock before July 1, 2004. Assuming the proposed CPUC settlement agreement is approved and the Settlement Plan implemented, the Utility does not anticipate paying a dividend until the later part of 2005.

CASH FLOWS

Utility

The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the nine months ended September 30, 2003, and 2002.

Operating Activities

The Utility's cash flows from operating activities for the nine months ended September 30, 2003, and 2002 were as follows:

	Nine months ended September 30,

(in millions)	2003		2002


Net income	$	861	$	1,592
Non-cash (income) expenses:
Depreciation, amortization, and decommissioning	916		880
Net reversal of ISO accrual	-		(970)
Change in accounts payable	350		139
Change in income taxes payable	437		179
Other uses of cash:
Payments authorized by the Bankruptcy Court on amounts classified as Liabilities Subject to Compromise	(83)		(1,180)
Other changes in operating assets and liabilities	58		614

Net cash provided by operating activities	$	2,539	$	1,254

Net cash provided by operating activities increased by $1,285 million during the nine months ended September 30, 2003, compared to the same period in 2002. This increase was primarily due to the following factors:

Payments on amounts classified as Liabilities Subject to Compromise decreased by $1,097 million in the nine months ended September 30, 2003, compared to the same period in 2002, due to significant pre-petition amounts paid to QFs in the nine months ended September 30, 2002, based on Bankruptcy Court-approved settlements;

Net income decreased by $731 million in the nine months ended September 30, 2003, compared to the same period in 2002. Net income in the nine months ended September 30, 2002, included a $970 million reduction to cost of electricity related to the reversal of ISO charges.

Investing Activities

The Utility's cash flows from investing activities for the nine months ended September 30, 2003, and 2002 were as follows:

	Nine months ended September 30,

(in millions)	2003		2002


Capital expenditures	$	(1,182)	$	(1,156)
Net proceeds from sale of assets	14		8
Other investing activities	(25)		16

Net cash used by investing activities	$	(1,193)	$	(1,132)

Net cash used by investing activities increased by $61 million during the nine months ended September 30, 2003, compared to the same period in 2002. The increase was primarily attributable to an increase in capital expenditures and other investing activities during the nine months ended September 30, 2003. Cash flows from other investing activities relate primarily to nuclear decommissioning funding and the change in nuclear fuel inventory during the period.

Financing Activities

The Utility's cash flows from financing activities for the nine months ended September 30, 2003, and 2002 were as follows:

	Nine months ended September 30,

(in millions)	2003		2002


Long-term debt issued, matured, redeemed, or repurchased	$	(280)	$	(333)
Rate reduction bonds matured	(213)		(213)
Other financing activities	(1)		-

Net cash used by financing activities	$	(494)	$	(546)

Net cash used by financing activities decreased by $52 million during the nine months ended September 30, 2003, compared to the same period in 2002. The decrease was mainly due to a $53 million decrease in principal repayments on mortgage bonds by order of the Bankruptcy Court during the nine months ended September 30, 2003, compared to the same period in 2002.

PG&E Corporation

The following section discusses PG&E Corporation's significant cash flows from operating, investing, and financing activities for the nine months ended September 30, 2003, and 2002.

Operating Activities

PG&E Corporation's cash flows from operating activities for the nine months ended September 30, 2003, and 2002 were as follows:

	Nine months ended September 30,

(in millions)	2003		2002


Net income	$	383	$	1,315
Loss from discontinued operations	365		156
Cumulative effect of changes in accounting principles	6		61

Net income from continuing operations	754		1,532
Non-cash (income) expenses:
Depreciation, amortization, and decommissioning	910		881
Deferred income taxes and tax credits - net	339		176
Other deferred charges and noncurrent liabilities	636		(188)
Loss from retirement of long-term debt	89		153
Other changes in operating assets and liabilities	188		(1,303)

Net cash provided by operating activities	$	2,916	$	1,251

Net cash provided by operating activities increased by $1,665 million during the nine months ended September 30, 2003, compared to the same period in 2002. This increase was primarily due to the effect of Utility cash flows from operations discussed above, and the following factors:

A decrease in charges associated with the retirement of long-term debt and the write-off of deferred financing costs.

An increase in other deferred charges and noncurrent liabilities primarily related to deferred tax benefits recognized in respect of NEGT, Inc. losses.

Investing Activities

PG&E Corporation's cash flows from investing activities for the nine months ended September 30, 2003, and 2002 were as follows:

(in millions)	Nine months ended September 30,

	2003		2002

Capital expenditures	$	(1,183)	$	(1,156)
Net proceeds from sale of assets	14		8
Other, net	(24)		15

Net cash used by investing activities	$	(1,193)	$	(1,133)

Net cash used by investing activities increased by $60 million during the nine months ended September 30, 2003, compared to the same period in 2002. This increase was primarily due to an increase in Utility capital expenditures.

Financing Activities

PG&E Corporation's cash flows from financing activities for the nine months ended September 30, 2003, and 2002 were as follows:

(in millions)	Nine months ended September 30,

	2003		2002

Long-term debt issued	582		564
Long-term debt matured, redeemed, or repurchased	(1,067)		(1,241)
Rate reduction bonds matured	(213)		(213)
Common stock issued	120		190
Other, net	(2)		-

Net cash used by financing activities	$	(580)	$	(700)

Net cash used by financing activities decreased by $120 million during the nine months ended September 30, 2003, compared to the same period in 2002. This decrease was primarily due to a reduction in cash used in financing activities by the Utility as discussed above, and an increase in long-term debt issued, offset by a decrease in long-term debt matured.

COMMITMENTS

The Utility has substantial financial commitments in connection with operating, construction, and development activities.

The Utility's contractual commitments include natural gas supply and transportation agreements, power purchase agreements (including agreements with QFs, irrigation districts and water agencies, bilateral power purchase contracts, and renewable energy contracts), nuclear fuel agreements, operating leases, and other commitments. The Bankruptcy Court has authorized certain payments and actions necessary for the Utility to continue its normal business operations while operating as a debtor-in-possession.

The Utility's commitments under financing arrangements include obligations to repay first and refunding mortgage bonds, senior notes, medium-term notes, pollution-control bond-related agreements, Deferrable Interest Subordinated Debentures, lines of credit, letters of credit, floating rate notes, and commercial paper. These commitments have been stayed by the Bankruptcy Court, although the Utility has requested and received permission to make scheduled maturity payments on secured debt as it comes due. In addition, the Utility has been making post-petition interest payments on its financing debt on the due dates.

PG&E Funding LLC, a wholly owned subsidiary of the Utility, also is obligated to make scheduled payments on its rate reduction bonds. These bonds are included as commitments of the Utility.

The Utility's contractual commitments and obligations are discussed in PG&E Corporation's and the Utility's 2002 Annual Report on Form 10-K, as amended, with updates to such disclosures included in Note 6 of the Notes to the Consolidated Financial Statements.

REGULATORY MATTERS

A significant portion of the Utility's operations is regulated by federal and state regulatory commissions. These commissions oversee service levels and, in certain cases, the Utility's revenues and pricing for its regulated services.

The discussion of these matters below should be read in conjunction with the regulatory matters discussed in PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended.

As discussed above, on June 19, 2003, PG&E Corporation, the Utility, and the staff of the CPUC announced a proposed settlement agreement for the Utility's Chapter 11 filing. If the proposed CPUC settlement agreement ultimately is approved, several of the regulatory proceedings discussed below would be impacted. The Utility cannot predict the ultimate outcome of the proposed CPUC settlement agreement, including when and whether it will be approved. Regulatory proceedings associated with the Utility's Chapter 11 proceeding and electric industry restructuring are further discussed in Notes 2 and 6 of the Notes to the Consolidated Financial Statements.

DWR Revenue Requirement

The DWR filed its proposed 2004 revenue requirement with the CPUC in September 2003. The DWR proposed a $4.5 billion revenue requirement for power charge-related costs in 2004 from the customers of the three California IOUs. The CPUC is responsible for allocating the proposed 2004 revenue requirement among the customers of the IOUs. The CPUC will allocate the 2004 DWR power charge revenue requirement on an interim basis using the methodology adopted for the allocation of the 2003 DWR power charge revenue requirement. A later phase of this proceeding, with testimony scheduled to be filed in December 2003, will finalize the allocation of the DWR power charge revenue requirement for 2004 and possibly for the remaining years of the DWR contracts.

In testimony submitted to the CPUC on October 15 and 22, 2003, the Utility estimated that it over-remitted $107 million in power charges to the DWR for the 2001- 2002 period based on the allocation methodology applied by the CPUC in determining the allocation of the 2001-2002 DWR power charge revenue requirement. The Utility also proposed that the CPUC use a different allocation methodology under which the Utility estimates it over-remitted $211 million. Testimony submitted by Southern California Edison (SCE) and other parties includes varying estimates of the Utility's true-up adjustment depending on the allocation methodology proposed. SCE calculated that the Utility over-remitted approximately $101 million in power charges to the DWR based on the allocation methodology applied by the CPUC in determining the allocation of the 2001-2002 DWR power charge revenue requirement. However, SCE also has proposed that the CPUC apply the allocation methodology used to allocate the DWR bond charge revenue requi rement to allocate the bond proceeds among the customers of the IOUs, and under this methodology, has estimated that the Utility has under-remitted a net $453 million in DWR revenue requirements. The Utility's testimony noted that the CPUC had already rejected this proposal in its decision allocating the DWR's 2003 bond charge revenue requirements.

DWR Bond Charge

The DWR completed an $11.3 billion bond financing in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR electricity revenue requirement and to provide the DWR with funds needed to make its electricity purchases. In October 2002, the CPUC issued a decision that, in part, imposes charges to recover the DWR's bond costs from bundled and direct access customers starting November 15, 2002, as described below, although the decision found that the Utility would not need to increase customers' overall rates to incorporate the bond charge. The Utility billed and is passing through approximately $272 million in bond-related charges for the nine months ended September 30, 2003. The Utility expects to bill and pass through DWR bond-related charges of approximately $352 million for 2003. As noted above under "DWR Revenue Requirement," SCE has proposed that the CPUC apply the allocation methodology used to allocate the DWR bond charge revenue requirement to allocate the bond proceeds among the customers of the IOUs, and under this methodology, has estimated that the Utility has under-remitted a net $453 million in DWR revenue requirements. The Utility's testimony noted that the CPUC had already rejected this proposal in its decision allocating the DWR's 2003 bond charge revenue requirements.

The DWR filed its proposed 2004 revenue requirement with the CPUC in September 2003. In this proposed revenue requirement, the DWR states that it expects to collect $873 million for bond-related costs in 2004 from the customers of the three California IOUs. The CPUC is responsible for allocating the proposed 2004 bond charge-related revenue requirement among the customers of the IOUs. Under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the CPUC has agreed that DWR bond charges allocated to the Utility's customers will be included in rates in a manner that will not affect the Utility's collection of other authorized costs or return on capital.

Allocation of DWR Electricity to Customers of the IOUs

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 contracts being assumed are just and reasonable; and

The CPUC has acted to ensure full and timely recovery in the Utility's retail electricity rates of all contract costs without further review.

Electricity Procurement

In October 2002, the CPUC issued a decision ordering the Utility to resume full procurement of electricity for its residual net open position on January 1, 2003, and to file short- and long-term procurement plans. On January 1, 2003, the Utility, along with the other California IOUs, also became responsible for scheduling and dispatch of the quantities subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. In December 2002, the CPUC adopted a 2003 interim procurement plan for the Utility. The CPUC also authorized the California IOUs to extend their planning into the first quarter of 2004 and directed the Utility to hedge its 2004 first quarter residual net open position with transactions entered into in 2003.

The Utility filed its long-term procurement plan (long-term plan), covering the next 20 years, on April 15, 2003. The Utility filed its short-term procurement plan covering 2004 in May 2003. The Utility expects that the CPUC will issue final decisions on both the Utility's long-term procurement plan and its short-term procurement plan in December 2003. In August 2003, the CPUC authorized the Utility to procure up to 50 percent of its non-baseload 2004 short-term procurement needs pending approval of the short-term procurement plan. The Utility conducted a competitive solicitation and submitted its selection criteria to the CPUC for approval.

Under AB 1X, the CPUC has no authority to review the reasonableness of procurement costs in the DWR's contracts, although the Utility's administration of the DWR allocated contracts and the Utility's dispatch of the electricity associated with the DWR allocated contracts may be subject to CPUC review. Under decisions entered in December 2002 and June 2003, the CPUC established a maximum annual procurement disallowance for administration of DWR contracts and least-cost dispatch equal to $36 million. Activities excluded from the disallowance cap include gas procurement activities in support of new Utility contracts, retained generation resources, QF contracts, and certain retained generation expenses. This maximum disallowance amount is subject to audit for the Utility's adopted annual administrative costs of managing procurement activities in the 2003 GRC. The Utility can provide no assurance that the CPUC will not increase or eliminate this maximum annual procurement disallowance in the future.

A central feature of the SB 1976 regulatory framework is its direction to the CPUC to create new electricity procurement balancing accounts to track and allow recovery of the differences between recorded revenues and costs incurred under an approved procurement plan. The CPUC must review the revenues and costs associated with an IOU's electricity procurement plan at least semi-annually and adjust rates or order refunds, as appropriate, to properly amortize the balancing accounts. The CPUC must establish the schedule for amortizing the over-collections or under-collections in the electricity procurement balancing accounts so that the aggregate over-collections or under-collections reflected in the accounts do not exceed 5 percent of the IOU's actual recorded generation revenues for the prior calendar year, excluding revenues collected on behalf of the DWR. Mandatory semi-annual review and adjustment of the balancing accounts will continue until January 1, 2006. Thereafter, the CPUC is required to condu ct electricity procurement balancing account reviews and adjust retail ratemaking amortization schedules for the balancing accounts as the CPUC deems appropriate and in a manner consistent with the requirements of SB 1976 for timely recovery of electricity procurement costs.

Effective January 1, 2003, the Utility established the Energy Resource Recovery Account (ERRA) to record and recover electricity costs, excluding the DWR's electricity contract costs, associated with the Utility's authorized procurement plan. (The ERRA also excludes the above-market portion of QF and power purchase agreement costs.) In February 2003, the Utility filed its 2003 ERRA forecast application requesting that the CPUC reset the Utility's 2003 ERRA revenue requirement to $1.4 billion and that the ERRA trigger threshold of $224 million be adopted. (The Utility is authorized to file an application to change retail electricity rates when it reaches the trigger threshold, i.e., when the Utility's forecasts indicate that it will face an under-collection of electricity procurement costs in excess of 5 percent of its prior year's generation and procurement revenues, excluding amounts collected for the DWR.) In August 2003, the Utility and the CPUC's Office of Ratepayer Advocates (ORA) proposed a stipulation to an Administrative Law Judge (ALJ) and the CPUC that would reduce the Utility's 2003 ERRA revenue requirement by $40 million to $1.37 billion. The CPUC issued a decision adopting the stipulation in October 2003.

In August 2003, the Utility filed an application requesting that the CPUC approve the Utility's 2004 ERRA forecast revenue requirement of $1.5 billion associated with the Utility's 2004 short-term procurement plan and approve as reasonable the Utility's ERRA recorded costs for the period from January 2003 through May 2003. The CPUC's review of the Utility's procurement activities will examine the Utility's least-cost dispatch of the resource portfolio, fuel expenses for the Utility's electricity generation, contract administration, including administration of the DWR allocated contracts, the Utility's existing QF contracts and other power purchase agreements, renewable energy contracts, and the decision to engage in market transactions in the context of the Utility's overall prudent contract administration and least-cost dispatch of generation resources. The Utility has also asked the CPUC to approve its proposed revenue requirement of $840 million to recover the 2004 costs related to the above-market g eneration and procurement costs and certain other generation-related costs.

In June 2003, the CPUC issued a decision pursuant to SB 1078 that adopts the framework for implementing a Renewable Portfolio Standard (RPS) program. The decision requires the Utility to increase procurement of renewable energy by at least 1 percent of its retail sales per year. By the end of 2017, the Utility must be procuring at least 20 percent of its total electricity from renewable resources. Under SB 1078, the Utility was not obligated to purchase additional renewable energy until it received an investment grade credit rating. However, under subsequently enacted SB 67, the Utility may be required to purchase additional renewable energy once it is able to do so on reasonable terms and the renewable energy contracts will not impair the restoration of its creditworthiness. Until that time, the Utility will accumulate an annual procurement target (APT) based on 1 percent of annual retail sales. When the Utility receives an investment grade credit rating or the CPUC determines that the SB 67 requir ements are satisfied, the Utility expects to enter into purchase contracts for renewable energy to meet its accumulated APT.

Although the Utility cannot predict what the terms, including price, of such contracts would be, the decision requires that the procurement price under such contracts to be at or below a market price benchmark established by the CPUC after the bids have been received. If the Utility exceeds its APT, it can apply the excess to meet the APT in future years. For under-procurement, the decision allows IOUs to carry over an annual deficit of 25 percent to the next three years without explanation. Failure to meet minimum APTs without prior CPUC approval would result in an automatic penalty of $0.05 per kWh, subject to an annual penalty cap of $25 million. The Utility currently estimates that the annual 1 percent increase in renewable resource electricity in its portfolio will initially require between 80 and 100 megawatts (MW) of additional renewable capacity to be added per year.

The CPUC approved offers the Utility submitted that were sufficient to meet the Utility's 2003 renewable energy requirement in December 2002. In September 2003, the Utility submitted to the CPUC for approval several renewable contracts pursuant to an assigned commissioner ruling in August 2003 that permitted bilateral negotiations with renewable suppliers prior to the implementation of renewable energy portfolio standard requirements. The CPUC approved the contracts in October 2003.

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

In April 2003, the ORA issued a report regarding the Utility's procurement activities for the period July 1, 2000, through June 30, 2001, recommending that the CPUC disallow recovery of $434 million of the Utility's procurement costs based on an allegation that the Utility's market purchases during the period were imprudent due to a failure to develop and execute a reasonable hedging strategy. The ORA recommendation does not take into account any FERC-ordered refunds of the Utility's procurement costs during this period, which refunds could effectively reduce the amount of the recommended disallowance. In the Utility's response to the ORA's report, the Utility indicated that the ORA recommendation is unlawful, contrary to prior CPUC decisions, and factually unsupported. Subsequently, the procedural schedule in this proceeding was suspended, pending the outcome of the proposed settlement agreement in the Utility's Chapter 11 proceeding.

Under the proposed CPUC settlement agreement, the CPUC would agree to act promptly to resolve this proceeding, with no adverse impact on the Utility's cost recovery, as soon as practicable after the Settlement Plan becomes effective.

Retained Generation Revenue Requirement

In April 2002, the CPUC issued a decision authorizing the Utility to recover reasonable costs incurred in 2002 for its own retained electric generation, subject to reasonableness review in the Utility's 2003 GRC or other proceedings. In May 2003, the CPUC issued a resolution approving the Utility's proposed tariff revisions and its request to establish various balancing and memorandum accounts with modifications in compliance with the CPUC's April 2002 decision.

In July 2003, the Utility reached an agreement (the "generation settlement agreement") with various intervenors that would set a 2003 generation revenue requirement of $955 million and filed a motion for approval with the CPUC. This generation revenue requirement excludes fuel expense, the cost of electricity purchases, the DWR revenue requirements, and nuclear decommissioning revenue requirements. If approved by the CPUC, the generation settlement agreement would resolve all generation-specific issues, but would not resolve various tax methodology issues or the amount of administrative and general expenses and common plant to allocate to generation.

The "2003 GRC settlement agreement" discussed below would resolve these remaining issues. If the generation settlement agreement and the 2003 GRC settlement agreement are approved by the CPUC, the Utility's revenue requirement for its electricity generation operations would be set at $912 million for 2003, an increase of $38 million over the currently authorized amount. In addition, the 2003 GRC settlement agreement provides for a new balancing account, effective January 1, 2004, to ensure that the Utility recovers its authorized electricity generation revenue requirement regardless of the level of sales.

In addition to the two settlement agreements discussed above, under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the Utility's adopted 2003 retained generation rate base of $1.6 billion would be deemed just and reasonable by the CPUC and not subject to modification, adjustment, or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. This reaffirmation of the Utility's electricity generation rate base would allow recognition of an after-tax regulatory asset of approximately $0.8 billion (or $1.3 billion pre-tax).

Direct Access Suspension and Cost Responsibility Surcharge

Until September 2001, California utility customers could choose to buy their electricity from the utility (bundled customers) or from an alternative power supplier through "direct access" service. Direct access customers receive distribution and transmission service from the utility, but purchase electricity (generation) from their alternative provider. In September 2001, the CPUC, pursuant to AB 1X, suspended the right of retail end-use customers to choose direct access service, thereby preventing additional customers from entering into contracts to purchase electricity from alternative providers. Customers that entered into direct access contracts on or before September 20, 2001, were permitted to remain on direct access.

In a November 2002 decision, the CPUC established a cost responsibility surcharge (CRS) mechanism to implement utility-specific non-bypassable charges on direct access customers for their shares of the bond costs and electricity costs incurred by the DWR and the above-market cost related to the Utility's generation resources and electricity purchase contracts. The November 2002 decision imposed a cap on the CRS of $0.027 per kWh. The Utility implemented this capped surcharge on January 1, 2003. A July 2003 decision ordered that the CRS funds be applied to recover (in the following order) the DWR bond charges, the Utility's ongoing above-market costs related to its generation resources and electricity purchase contracts, and the DWR power charges.

The July 2003 decision found that, subject to prospective adjustment in the annual DWR revenue requirement proceeding, the CRS cap of $0.027 per kWh, plus interest on the direct access CRS under-collection, will be sufficient to repay any shortfall to customers who receive bundled service by the time the DWR allocated contracts terminate. The CPUC has also held in April and July 2003 decisions that certain customers reducing or terminating the Utility's electricity service after February 2001 should be responsible for payment of the CRS, subject to specific exemptions.

To the extent the CRS cap results in an under-collection of DWR charges, the Utility would have to remit the shortfall to the DWR from bundled customers' funds. Since DWR pass-through revenues are determined based upon a fixed revenue requirement, to the extent that the Utility remits additional CRS amounts to the DWR, those remittances reduce the amount of revenues it must pass through for bundled customers. The Utility expects to collect approximately $110 million per year more in 2003 than in 2002 from direct access customers due to the CRS.

The Utility does not expect that the CPUC's implementation of this decision or the level of the CRS cap as detailed above to have a material adverse effect on its results of operations or financial condition.

Community Choice Aggregators

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

One-Cent, Three-Cent, and Half-Cent Surcharge Revenues

In January 2001, the CPUC increased electric rates by $0.01 per kWh, in March 2001 by another $0.03 per kWh, and in May 2001 by an additional $0.005 per kWh. The use of these surcharge revenues was restricted to "ongoing procurement costs" and "future power purchases." In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. Based on these decisions and an agreement between the CPUC and SCE, in which SCE was allowed to use its $0.005 per kWh surcharge to offset its DWR revenue requirement, the Utility has continued to recognize revenues related to the $0.01 per kWh, $0.03 per kWh, and $0.005 per kWh surcharges after the statutory end of the retail electric rate freeze, which was March 31, 2002, even without considering the proposed CPUC settlement agreement in the Utility's Chapter 11 proceed ing. (See further discussion in Note 2 of the Notes to the Consolidated Financial Statements.) As such, the Utility has not recorded a regulatory liability or a reserve for the potential refund of these surcharge revenues, or any portion thereof, as of September 30, 2003. From January 2001 to September 30, 2003, the Utility recognized total surcharge revenues of approximately $7.5 billion, pre-tax.

The Utility's ability to retain its surcharge revenues may be adversely affected if the proposed CPUC settlement agreement and Settlement Plan are not implemented or if, either in response to certain judicial decisions or on its own initiative, the CPUC changes its interpretation of law or otherwise seeks to change the Utility's overall retail electric rates retroactively. (See further discussion in "Surcharge Revenues" in Note 6 of the Notes to the Consolidated Financial Statements.)

Under the proposed CPUC settlement agreement, the CPUC would acknowledge and would agree that the revenues related to the surcharges described above are the property of the Utility's Chapter 11 estate and are not subject to refund. If the proposed CPUC settlement agreement is not approved and the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially adversely affected.

2003 General Rate Case

In the Utility's 2003 GRC, the CPUC will determine the amount of authorized base revenues the Utility can collect from ratepayers to recover its basic business and operational costs for gas and electric distribution operations for 2003 and succeeding years. As discussed above under "Retained Generation Revenue Requirement," the CPUC will also determine in this 2003 GRC the amount of authorized base revenues the Utility can collect from ratepayers to recover its basic business and operational costs for the Utility's retained generation.

In September 2003, the Utility and various intervenors (TURN, the CPUC's ORA, Aglet Consumer Alliance, the Modesto Irrigation District, the Natural Resources Defense Council, and the Agricultural Energy Consumers Association) filed a joint motion with the CPUC seeking approval of a settlement agreement these parties entered into in the Utility's 2003 GRC proceeding (2003 GRC settlement agreement), also filed with the CPUC. The parties reached agreement on all disputed economic issues related to the electricity and natural gas distribution revenue requirement of the 2003 GRC, with the exception of the Utility's request that the CPUC include the costs of a pension contribution in the Utility's revenue requirement. The CPUC will resolve the pension contribution issue, as well as other issues raised by non-settling intervenors, based upon briefs submitted on September 17, 2003, and reply briefs submitted on October 8, 2003, in its final decision and the Utility's GRC revenue requirements will be adjusted ap propriately.

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

The parties have agreed that the Utility's next GRC will be to determine rates for test year 2007.

Attrition Rate Adjustments for 2004 - 2006

The Utility may receive annual increases in the base revenues established during the test year of a GRC, known as attrition rate adjustments (ARAs), for the years between GRCs to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. Under the generation settlement agreement and the 2003 GRC settlement agreement, attrition revenue increases for electric and natural gas distribution and electric generation operations for 2004, 2005, and 2006 would be authorized in the 2003 GRC. The attrition increase for 2004 and 2005 would be calculated as the prior year's revenue requirement multiplied by the change in the Consumer Price Index (CPI). To calculate the attrition increase for 2006, the 2005 revenue requirement would be multiplied by the change in the CPI plus 1.0 percent. The generation attrition revenue requirement would also include additional revenues to cover the costs of refueling activities at the Utility's Diablo Canyon Power Plan t. For electric and natural gas distribution operations, the attrition increases would be subject to a minimum increase of 2.0 percent and a maximum increase of 3.0 percent for 2004, a minimum increase of 2.25 percent and a maximum increase of 3.25 percent for 2005, and a minimum increase of 3.0 percent and a maximum increase of 4.0 percent for 2006. For electric generation operations, the attrition increases would be subject to a minimum increase of 1.5 percent and a maximum increase of 3.0 percent for 2004 and 2005, and a minimum increase of 2.5 percent and a maximum increase of 4.0 percent for 2006. The GRC settlement agreement notes that outcomes in future cost of capital proceedings, in which the CPUC determines the authorized rate of return that the Utility may earn on its electric and gas distribution and electric generation assets, could affect the Utility's revenue requirement, including the attrition adjustments.

2002 Attrition Rate Adjustment Request

In April 2003, the Utility filed an application for rehearing of the CPUC's March 2003 decision, which denied the Utility's request for a $76.7 million increase to its annual electric distribution revenue requirement and a $19.5 million increase to its annual gas distribution revenue requirement for 2002. In the filing, the Utility contends that the CPUC's denial of attrition relief was in error because the decision applied the wrong legal standard and because its findings were not supported by substantial evidence. In October 2003, the CPUC issued a final decision denying the Utility's application for rehearing.

Cost of Capital Proceedings

Each year, the Utility files an application with the CPUC to determine the authorized rate of return the Utility may earn on its electric and gas distribution and electric generation assets.

For its gas and electric distribution operations and electric generation operations, the Utility's currently authorized ROE is 11.22 percent and its currently authorized cost of debt is 7.57 percent. The Utility also has a currently authorized capital structure of 48.00 percent common equity, 46.20 percent long-term debt, and 5.80 percent preferred equity. The November 2002 decision in the Utility's 2003 Cost of Capital proceeding adopted these authorized figures but held the case open to address the effect that implementing and financing a confirmed plan of reorganization would have on the Utility's ROE, costs of debt and preferred stock, and ratemaking capital structure. Subsequently, in February 2003, the Utility filed a petition to modify the November 2002 decision to waive the normal requirement that the Utility file a test year 2004 cost of capital application. In May 2003, the CPUC granted the Utility's request, exempting the Utility from filing a test year 2004 cost of capital application.

The proposed CPUC settlement agreement provides that the Utility's authorized ROE would be no less than 11.22 percent per year and the Utility's authorized equity ratio for ratemaking purposes would be no less than 52 percent, except that, for 2004 and 2005, the Utility's authorized equity ratio would equal the greater of the proportion of equity in the forecast of the Utility's average capital structure for calendar years 2004 and 2005 filed in the Utility's cost of capital proceedings and 48.6 percent.

FERC Prospective Price Mitigation Relief

Various parties, including the Utility and the State of California, are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of electricity purchasers. In December 2002, a FERC ALJ issued an initial decision finding that power suppliers overcharged the utilities, the State of California, and other buyers $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 $3.0 billion, leaving $1.2 billion in net unpaid bills.

In March 2003, the FERC confirmed most of the ALJ's findings, but partially modified the refund methodology to include use of a new gas price methodology as the basis for mitigated prices. In October 2003, the FERC issued a decision confirming the modified refund methodology set forth in the March 2003 order and directed the ISO and the Power Exchange (PX) to make compliance filings establishing refund amounts by March 2004. The modified refund methodology included use of a new gas price methodology as the basis for mitigated prices and directed the ISO and the PX to make compliance filings establishing refund amounts by March 2004. The actual refunds will not be determined until the FERC issues a final decision, which is expected in the first half of 2004. In addition, future refunds could increase or decrease as a result of the ISO Amendment 51 proceeding. The Amendment 51 proceeding is an ISO tariff amendment that proposes certain adjustments to ISO data and treatment of ISO charges to permit calc ulation of FERC refunds from a database that the ISO considers appropriate for such calculations. A decision in this proceeding is expected in November 2003. Under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, 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. Refunds, claim offsets, or other credits from generators or other energy suppliers relating to the Utility's electricity purchase costs, once tax effected, will reduce the $2.21 billion after-tax regulatory asset created by the proposed CPUC settlement agreement.

The Utility has recorded $1.8 billion of claims filed by various electricity generators in its Chapter 11 case as Liabilities Subject to Compromise. The Utility currently estimates that these claims would have been reduced to approximately $1.2 billion based on the refund methodology recommended in the ALJ's initial decision. The recent recalculation of market prices according to the revised methodology adopted by the FERC in its October 2003 decision could result in a reduction of several hundred million dollars in the amount of the suppliers' claims. This reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they provide evidence that natural gas prices were higher than the natural gas prices assumed in the refund methodology and are acceptable to the FERC in future FERC decisions.

On June 25, 2003, the FERC issued a series of orders directing more than 40 companies to show cause why they should not disgorge profits for a variety of violations of the ISO and PX tariffs related to market manipulation during the summer of 2000. The Utility was named as one of the companies in these orders. The Utility has shown that some transactions were misidentified and do not relate to it, and that other identified transactions did not constitute improper behavior, but rather justifiable transactions under the operational circumstances. On October 30, 2003, the FERC staff filed a motion to dismiss the Utility from this proceeding. The Utility does not expect the outcome to have a material adverse impact on its consolidated financial position or results of operations.

In June 2003, the FERC also began an investigation of why companies should not disgorge profits related to electricity bids in violation of ISO and PX tariffs during the period from May 1 to October 1, 2000. The Utility submitted information explaining its bidding, which was designed to ensure optimal dispatch of its resources, including when and at what level it operated its hydroelectric generating facilities. Since the Utility was a net purchaser of electricity during this period, the Utility expects that the amount it would be required to pay, if any, would be offset by the refunds it would receive from other companies. Assuming the Utility receives refunds from other companies, the Utility does not expect the outcome to have a material adverse impact on its consolidated financial position or results of operations. This proceeding is being conducted as a FERC staff investigation and results are not expected until the first half of 2004. However, some cases may be resolved by settlements and one s ettlement proposed by the FERC staff with a seller has proposed payments of up to $25 million and additional compensation in the form of options to purchase rights to generation.

FERC Transmission Rate Cases

On January 13, 2003, the Utility filed an application with the FERC requesting authority to recover $545 million in electric transmission retail rates annually, an increase of $166 million over the revenue requirement then in effect. The requested increase is mainly attributable to significant capital additions and replacements made to the Utility's system to accommodate load growth, maintain the infrastructure, and ensure safe and reliable service. In addition, the request includes a 15-year useful life for transmission plant coming into service in 2003 and a ROE of 13.5 percent. The January 13, 2003 proposed rates went into effect, subject to refund, on August 13, 2003.

The Utility filed an additional rate application with the FERC at the end of October 2003 requesting recovery of $530 million per year, subject to refund, in electric transmission retail rates, a slight decrease from rates currently in effect. The filing requests a 13.0 percent ROE and seeks recovery of the Utility's costs of providing safe and reliable transmission service during 2004.

El Paso Settlement

In June 2003, the Utility, along with a number of other parties, entered into the El Paso settlement, which resolves all potential and alleged causes of action against El Paso for its part in alleged manipulation of natural gas and electricity commodity and transportation markets during the period from September 1996 to March 2003. Under the El Paso settlement's terms, El Paso will pay $1.5 billion in cash and non-cash consideration. Of that total, approximately $352 million will be paid up front, another approximately $227 million (depending on the proceeds) will be paid from the sale of El Paso stock and approximately $875 million will be paid over 15 to 20 years. El Paso also agreed to a $125 million reduction in El Paso's long-term electricity supply contracts with the DWR, to provide pipeline capacity to California and to ensure specific reserve capacity for the Utility, if needed. The exact amounts allocated to each entity are detailed in a master settlement agreement and delineated in an alloca tion agreement. In October 2003, the CPUC issued a decision to complete the final allocation of these refunds, under which the Utility's natural gas ratepayer would receive approximately $75 million and its electricity ratepayers would receive approximately $210 million. The agreement is now pending approval by the FERC and the San Diego County Superior Court.

It is uncertain whether or when these required approvals will be obtained. The proposed CPUC settlement agreement provides that the net after-tax amount of any consideration that the Utility actually realizes in cash related to the electricity refunds (but not the natural gas refunds) would reduce the new $2.21 billion after-tax regulatory asset if consistent with CPUC rules and orders.

Gas Accord II

In 1998, the Utility implemented a ratemaking pact called the Gas Accord, under which the Utility's natural gas transportation and storage services were separated for ratemaking purposes from its distribution services. The Gas Accord established natural gas transportation rates through 2002 and natural gas storage rates through March 2003. In addition, the Gas Accord established an incentive mechanism whereby the Utility recovers its costs of purchasing natural gas for its residential and smaller commercial, or core, customers. Under the Gas Accord, the Utility is at risk of not recovering its natural gas transportation and storage costs and does not have regulatory balancing account protection for over-collections or under-collections of natural gas transportation or storage revenues.

In August 2002, the CPUC approved the Gas Accord settlement that provided for a one-year extension of the Utility's existing natural gas transportation rates and terms and conditions of service, as well as rules governing contract extensions and a contract solicitation period for new contracts. In January 2003, the Utility filed an amended Gas Accord II application with the CPUC proposing to permanently retain the Gas Accord market structure, extend the incentive mechanism for recovery of core procurement costs, and increase the Utility's rates for natural gas transportation service for 2004 and for storage service for the period from April 1, 2004, to March 31, 2005, by $55 million. Subsequently, the CPUC removed the cost of capital issues from this proceeding, resulting in a $25 million reduction in the Utility's revenue requirement request.

The amended Gas Accord II application proposed a rate increase for 2004, calculated on a demand or throughput forecast basis. In addition, for the 12-month period ending December 31, 2004, for transportation service, and for the 12-month period ending March 31, 2005, for storage service, the Utility proposes to provide an option for current holders of contract capacity to extend their rights and for a structured contract solicitation period to be held for any capacity that is not under contract. The Utility may experience a material reduction in operating revenues if (1) the Utility were unable to renew or replace existing transportation contracts at the beginning or throughout the Gas Accord II period, (2) the Utility were forced to renew or replace those contracts on less favorable terms than adopted by the CPUC, or (3) overall demand for transportation and storage services were less than anticipated and reflected by the CPUC in rates. A CPUC decision in this proceeding is expected in December 2003. Until the CPUC issues a decision, the existing natural gas transportation and storage rates will continue in effect.

The Utility cannot predict what the outcome of this proceeding will be, or whether the outcome will have a material adverse effect on its results of operations or financial condition.

Annual Earnings Assessment Proceeding for Energy Efficiency Program Activities

The Utility administers general and low-income energy efficiency programs, and has been authorized to earn incentives based on a portion of the net present value of the savings achieved by the programs, incentives based on accomplishing certain tasks, and incentives based on expenditures. Each year the Utility files an earnings claim in the Annual Earnings Assessment Proceeding (AEAP), a forum for stakeholders to comment on, and for the CPUC to verify, the Utility's claim. In March 2002, the CPUC eliminated the opportunity for shareholder incentives in connection with the California IOUs' 2002 energy efficiency programs. This decision does not preclude the opportunity to recover shareholder incentives in connection with previous years' energy efficiency programs.

In May 2003, 2002, 2001, and 2000, the Utility filed its annual applications claiming incentives totaling approximately $106 million, consisting of $74 million for pre-1998 energy efficiency programs, $30 million for post-1997 energy efficiency programs, and $1.6 million for low-income programs. The Utility has not included any earnings associated with incentives in the Utility's Consolidated Statements of Income.

Since March 2002, the CPUC had not taken any significant action on the applications while it considered whether the incentive mechanism adopted for pre-1998 energy efficiency programs should be reduced or eliminated for claims in future years. In October 2003, the CPUC issued a decision confirming that the shared savings shareholder incentive mechanism adopted for energy efficiency shareholder incentives in the AEAPs should not be modified. The decision further indicated that all of the earnings claims remain subject to verification, in accordance with the Commission's adopted measurement and evaluation protocols. The CPUC verification lead consultant has begun the verification process and the consultant's report should be completed in the first quarter of 2004.

Under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would agree to act promptly on pending Utility ratemaking proceedings, including the AEAP applications. Once the consultant's reports are issued, the Utility expects that the applications should proceed reasonably quickly.

In August 2003, the CPUC authorized the recovery of $0.1 million associated with the earnings claim for electric low-income programs in 1998 and held recovery of the Utility's 1999, 2000, and 2001 claims pending the results of the consultant's verification reports. The Utility was also ordered to track the low-income earnings claims for 1999, 2000, and 2001 in a memorandum account.

The 2003 AEAP hearing process began with a pre-hearing conference in July 2003. The 2003 AEAP is not consolidated with the 2002, 2001, and 2000 AEAPs.

The Utility does not expect that the outcome of these proceedings will have a material adverse effect on its results of operations or financial condition.

Nuclear Decommissioning Cost Triennial Proceeding

In March 2002, the Utility filed an application to increase the Utility's nuclear decommissioning revenue requirements for the years 2003 through 2005. The Utility sought to recover $24 million in revenue requirements relating to the Diablo Canyon Nuclear Decommissioning Trusts and $17.5 million in revenue requirements relating to the Humboldt Bay Power Plant Decommissioning Trusts. The Utility also sought recovery of $8.3 million in CPUC-jurisdictional revenue requirements for Humboldt Bay Unit 3 SAFSTOR (a mode of decommissioning) operating and maintenance costs, and escalation associated with that amount in 2004 and 2005.

In October 2003, the CPUC issued a decision adopting 2003 revenue requirements of $18.4 million for decommissioning the Humboldt Bay Power Plant and approved the Utility's request to begin decommissioning the Humboldt Bay Power Plant in 2006 instead of 2015. The decision further grants a revenue requirement of $8.3 million for Humboldt SAFSTOR operating and maintenance costs. In the same decision, the CPUC adopted no revenue requirement for decommissioning the Diablo Canyon Power Plant, finding that the trust funds for Diablo Canyon are sufficient to pay for its eventual decommissioning. The total adopted annual revenue requirement of $26.7 million represents a $4.5 million decrease from the previously adopted revenue requirement of $31.2 million.

Baseline Allowance Increase

In April 2002, the CPUC required the Utility to increase baseline allowances for certain residential customers by May 1, 2002. An increase to a customer's baseline allowance increases the amount of their monthly usage that is covered under the lowest possible rate and is exempt from the average $0.03 per kWh surcharge. The CPUC deferred consideration of corresponding rate changes until a later phase of the proceeding and ordered the utilities to track the under-collections associated with their respective baseline quantity changes in an interest-bearing balancing account. The Utility is charging the electric-related shortfall against earnings because it cannot predict the outcome of the second phase of the proceeding, nor can it conclude that recovery of the electric-related balancing account is probable. The total electric revenue shortfall for the period May through December 2002 was $70 million. The total electric revenue shortfall for the nine-month period from January 1, 2003, through September 30, 2003, was $81 million.

Issues expected to be resolved during the second phase of the proceeding include a number of proposals that would result in additional revenue shortfalls. These proposals include demographic revisions to baseline allowances, special allowances, and changes to baseline territories or seasons. The Utility estimates that the upper range of additional annual electric revenue shortfalls, if all such proposals were adopted in this second phase, could total $55 million per year, plus $10 million in administration costs spread out over three to five years. A proposed decision issued by the CPUC in October 2003 would reject all but two of these proposals: (1) a waiver of Tier 3 electric surcharges for larger lower-middle income households, and (2) a revision to gas and electric baseline quantities in the Utility climate zones in which exclusion of seasonal residences' lower usage would increase baseline allowances by at least 3 percent. If adopted as written, the Utility estimates that the pro posed decision could result in annual electric shortfalls of up to $16 million, plus $2 million in initial administrative costs.

The Utility cannot predict what the final outcome of the second phase of the proceeding will be, nor can it conclude that recovery of the electric baseline related balancing account is probable. Any electric revenue shortfalls will continue to be charged to earnings and will reduce revenue available to recover previously written-off under-collected purchased power costs and transition costs.

RISK MANAGEMENT ACTIVITIES

PG&E Corporation and the Utility are exposed to various risks associated with their operations, the marketplace, contractual obligations, financing arrangements, and other aspects of their business. PG&E Corporation and the Utility actively manage these risks through risk management programs. These programs are designed to support business objectives, minimize costs, discourage unauthorized risk, reduce the volatility of earnings and manage cash flows. At PG&E Corporation and the Utility, risk management activities often include the use of energy and financial derivative instruments and other instruments and agreements. These derivatives include forward contracts, futures, swaps, options, and other contracts.

PG&E Corporation and the Utility use derivatives for non-trading (i.e., risk mitigation) purposes. PG&E Corporation and the Utility enter into derivatives to mitigate the risks associated with an asset (e.g., the natural position embedded in asset ownership and regulatory arrangements), liability, committed transaction, or probable forecasted transaction. Derivatives are used in accordance with approved risk management policies adopted by a senior officer-level risk oversight committee. Entering into derivatives is permitted only after the risk oversight committee approves appropriate risk limits for such activity. The organizational unit proposing the activity must successfully demonstrate that there is a business need for such activity and that the market and credit risks will be adequately measured, monitored, and controlled.

As discussed in the "Liquidity and Financial Resources" section of this MD&A and Note 4 of the Notes to the Consolidated Financial Statements, effective July 8, 2003, NEGT, Inc.'s financial results are no longer consolidated with those of PG&E Corporation and are classified as discontinued operations. Upon deconsolidation of NEGT, Inc., the only risk management activities reported relate to Utility non-trading activities.

PG&E Corporation and the Utility estimated the gross mark-to-market value of their respective non-trading contracts at September 30, 2003, using the mid-point of quoted bid and ask forward prices, where available. When market data is not available, PG&E Corporation and the Utility use models to estimate forward prices with the support of third-party expert applications. Currently, the non-trading contracts of PG&E Corporation and the Utility are marked to market using spread option valuation models.

Market Risk

Market risk is the risk that changes in market conditions will adversely affect earnings or cash flow. PG&E Corporation and the Utility categorize market risks as price risk, interest rate risk, foreign currency risk, and credit risk. PG&E Corporation no longer retains significant influence over NEGT, Inc. as a result of their Chapter 11 filing on July 8, 2003. As of this date, PG&E Corporation accounts for its investment in NEGT, Inc. under the cost method of accounting and consequently NEGT, Inc.'s future financial results and market risk will not impact PG&E Corporation.

Price Risk

Price risk is the risk that changes in commodity market prices will adversely affect earnings and cash flows. The Utility is exposed to price risk, which consists of electric commodity (including purchased power and nuclear fuel) and natural gas commodity price risks, as described below. Also described below is the value-at-risk methodology, which is PG&E Corporation's and the Utility's method for assessing the prospective price risk that exists within a portfolio.

Electric Commodity Price Risk

On January 1, 2003, the Utility became responsible for scheduling and dispatching, on a least-cost basis, electricity allocated under contracts entered into by the DWR to fulfill the Utility's customers' electricity requirements. While the DWR continues to be legally and financially responsible for these contracts, the Utility relies on electricity provided by the DWR allocated contracts to service a significant portion of its total load. Customers are billed for these DWR electricity purchases and the Utility remits amounts collected to the DWR based on the DWR's CPUC-approved revenue requirement.

Beginning January 1, 2003, the Utility began purchasing electricity on the spot market to meet its residual net open position. The residual net open position will increase over time for a number of reasons, including:

Periodic expirations of existing electricity purchase contracts;

Periodic expirations or other terminations of the DWR allocated contracts; and

Increases in customers' electricity demands due to customer and economic growth or other factors.

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

In December 2002, the CPUC issued an interim opinion granting the Utility authority to enter into contracts designed to meet and to hedge the residual net open position through the first quarter of 2004. The Utility entered into contracts to supply 2003 peak capacity, all of which expired after the peak summer months. The Utility expects to enter into contracts to supply peak capacity demand in future years based upon annual CPUC approvals. In connection with these transactions the Utility expects it will be required to post collateral with the ISO and other counterparties. The Utility also buys electricity in short-term market transactions (i.e. forward contracts ranging from one hour ahead to one month ahead).

California's SB 1976 directed the CPUC to increase rates if the available revenue does not cover forecasted costs of purchasing electricity, and the shortfall exceeds 5 percent of prior year's generation revenue, excluding amounts collected for the DWR. Because these amounts collected for the DWR are excluded from this shortfall calculation, to the extent that the CPUC increases the portion of the DWR's revenue requirement allocated to the Utility's customers to cover adverse market price changes or other factors, the Utility has commodity price risk.

The amount of electricity provided by the DWR allocated contracts will likely result in surplus electricity during certain periods. The Utility plans to sell this surplus electricity on the open market. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's share of surplus sales revenues are included in its calculation determining whether it faces an under-collection of electricity procurement costs and is subject to review and recovery within the ERRA procedures discussed under "Electricity Procurement" in the "Regulatory Matters" section of this MD&A.

Nuclear Fuel

The Utility has purchase agreements for nuclear fuel. The Utility relies on large, well-established international producers for its long-term nuclear fuel agreements in order to diversify its commitments and ensure security of supply. Pricing terms are also diversified, ranging from fixed prices to base prices that are adjusted using published information.

Nuclear fuel purchases are subject to tariffs of up to 50 percent on imports from certain countries. Nuclear fuel costs have not increased based on the imposed tariffs because the terms of the existing long-term contracts did not include such costs. However, once these contracts expire in 2004, the costs under new nuclear fuel contracts may increase. As noted above, the CPUC is obligated to change retail electricity rates at any time that forecasts indicate the Utility will face an under-collection of electricity procurement costs, including the cost of nuclear fuel, in excess of 5 percent of prior year's generation revenues, excluding amounts collected for the DWR.

On August 14, 2003, the Utility entered into an agreement with AmerenUE and TXU Generation LP to form FuelCo, a limited liability company under the laws of the State of Delaware. The purpose of FuelCo is to assist its utility members to purchase nuclear fuel and related services in an efficient and cost-effective manner, principally by acting as agent in fuel procurement transactions. (The members have agreed to share out-of-pocket administrative expenses equally, although the Utility will initially have an ownership interest of less than 5 percent.)

Natural Gas Commodity Price Risk and Transportation Revenue Risk

The Utility recovers natural gas purchase costs through billings to customers. Under the Core Procurement Incentive Mechanism (CPIM), the Utility is allowed to adjust natural gas rates on a monthly basis. 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 were the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99 percent to 102 percent around the benchmark, are considered reasonable and are fully recovered in customer rates. Currently, one-half of the costs outside the tolerance band are recoverable customer rates, and customers receive the benefits of one-half of any savings outside the tolerance band in their rates. However, in June 2003, the Utility entered into a settlement with the ORA that, if approved by the CPUC, would increase the amount of savings passed through to ratepayers from one-half to three-fourths, retroactive to November 1, 2002. Under the proposal, ratepayers would continue to bear one-half of the costs incurred above the tolerance band.

In addition, the Utility has contracts for natural gas transportation capacity on various natural gas pipelines. In July 2002, the CPUC ordered IOUs to contract for a certain amount of El Paso pipeline capacity to gain firm access to the southwest natural gas producing basins. The CPUC pre-approved the costs of these contracts as just and reasonable. The July decision also ordered the utilities to retain their then-current interstate pipeline capacity levels and sell any excess capacity to a third party under short-term capacity release arrangements. It also ordered that, to the extent the utilities comply with the decision, they would be able to fully recover their costs associated with existing capacity contracts.

Under a previous CPUC decision, costs paid to Transwestern for gas pipeline capacity through 1997 were not recoverable. The Gas Accord provided for partial recovery of Transwestern costs from 1998 forward. In June 2003, a settlement agreement was reached with TURN that would allow the Utility to fully recover Transwestern costs beginning in July 2003. The CPUC has not yet approved the settlement.

Under the Gas Accord settlement, as with the Gas Accord, the Utility is at risk for any natural gas transportation revenue volatility. Capacity is sold at competitive market-based rates within a cost-of-service tariff framework. The Utility currently faces price risk for the part of intrastate natural gas transportation capacity that is not used by core customers. There are significant seasonal and annual fluctuations in demand for natural gas transportation services. Because the Utility sells most of its capacity based on the volume of natural gas customers actually ship rather than through long-term firm capacity contracts, natural gas transportation revenues will fluctuate.

Value-at-Risk

PG&E Corporation and the Utility measure price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the probability of future potential losses. Price risk is quantified using what is referred to as the variance-covariance technique of measuring value-at-risk, which provides a consistent measure of risk across diverse energy markets and products. This methodology relies on a number of important assumptions, including a confidence level for losses, price volatility, market liquidity, and a specified holding period. This technique uses historical price movement data and specific, defined mathematical parameters to estimate the characteristics of, and the relationships between, components of assets and liabilities held for price risk management (PRM) activities. PG&E Corporation and the Utility therefore use the historical data for calculating the expected price volatility of their portfolios' contractual positions to project the likelihood that the prices of those positions will move together.

PG&E Corporation's and the Utility's value-at-risk calculation is a dollar amount reflecting the maximum potential one-day loss in the fair value of their portfolios due to adverse market movements over a defined time horizon within a specified confidence level. This calculation is based on a 95 percent confidence level, which means that there is a 5 percent probability that PG&E Corporation's portfolios will incur a loss 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 percent probability that if prices moved against current positions, the reduction in the value of the portfolio resulting from such one-day price movements would not exceed $5 million. There also would be a 5 percent probability that a one-day price movement would be greater than $5 million.

The value-at-risk exposure for the Utility's non-trading activities includes substantially all derivatives in its natural gas portfolio, with the exception of financial options, over the entire length of the terms of the transactions. Since January 1, 2003, when the Utility resumed procurement of electricity, the Utility has been measuring certain of the risks embedded in the electricity portfolio, and ensuring that it is within the risk limits adopted in the CPUC's December 2002 interim opinion on the Utility's electricity procurement plan.

The potential one-day unfavorable impact for price risk as measured by the value-at-risk model, based on a one-day holding period was $6 million at September 30, 2003, and $4 million at December 31, 2002, for the Utility's natural gas portfolio. A comparison of daily values-at-risk at September 30, 2003, and at December 31, 2002, is included in order to provide context around the one-day amounts. The Utility's value-at-risk has increased at September 30, 2003, as compared to levels at December 31, 2002, due to increases in natural gas prices and volatility.

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, inadequate indication of the exposure of a portfolio to extreme price movements, and the inability to address the risk resulting from intra-day trading activities. Value-at-risk also does not reflect the significant regulatory and legislative risks currently facing the Utility or the risks relating to the Utility's Chapter 11 proceeding.

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. Specific interest rate risks for PG&E Corporation and the Utility include the risk of increasing interest rates on variable rate obligations.

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At September 30, 2003, if interest rates changed by 1 percent 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.

As discussed above under "Terms of the Settlement Plan," the Utility plans to issue debt to facilitate payment of allowed claims in the Utility's Chapter 11 case. The Utility anticipates that all costs associated with the debt will be fully recoverable. The Utility filed a petition with the CPUC during the third quarter of 2003 requesting authorization to enter into interest rate hedges on up to $7.4 billion of debt that would be issued under any plan of reorganization because of the current low interest rate environment and the possibility of interest rates rising in the period when the Utility expects to issue debt to emerge from bankruptcy. On September 4, 2003, the CPUC issued a decision authorizing interest rate hedging to mitigate the final costs of the plan of reorganization, subject to the approval of the actual transactions by the CPUC's financing team (consisting of the Director of the CPUC's Energy Division and the designee of the CPUC's General Counsel). The CPUC's financing team issued a letter of authorization on October 24, 2003, authorizing the Utility to enter into specific interest rate hedges.

The Utility also petitioned the Bankruptcy Court for the authority to enter into interest rate hedges in August 2003, with a maximum cost of up to an aggregate of $90 million and with settlement dates through June 30, 2004. Bankruptcy Court approval was received on September 26, 2003.

On October 31, 2003, and November 3, 2003, the Utility entered into interest rate hedges to reduce the impact to ratepayers resulting from possible significant increases in interest rates on the debt to be issued.

Foreign Currency Risk

Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies in relation to the U.S. dollar. The Utility is exposed to such risk associated with foreign currency exchange variations related to Canadian-denominated purchase and swap agreements.

Changes in gas purchase costs due to fluctuations in the value of the Canadian dollar would be passed through to customers in rates, as long as the overall costs of purchasing gas are within a 99 percent to 102 percent tolerance band around the benchmark price under the CPIM mechanism, as discussed above.

The Utility uses sensitivity analysis to measure exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at September 30, 2003, a 10 percent devaluation of the Canadian dollar would be immaterial to the Utility's Consolidated Financial Statements.

Credit Risk

(in millions)		Gross Credit Exposure Before Credit Collateral ⁽¹⁾		Credit Collateral		Net Credit Exposure ⁽²⁾		Number of Counterparties >10 percent	Net Exposure of Counterparties >10 percent


September 30, 2003 ⁽³⁾		$	141	$	8	$	133	4	$	76
December 31, 2002		288		113		175		2	55

⁽¹⁾	Gross credit exposure equals mark-to-market value, notes receivable, and net (payables) receivables where netting is 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 incurred prior to the Utility's Chapter 11 filing 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.
⁽³⁾	Excludes post-petition exposures to Enron.

The schedule below summarizes the credit quality of the Utility's net credit risk exposure to counterparties at September 30, 2003, and December 31, 2002.

Credit Quality ⁽¹⁾		Net Credit Exposure ⁽²⁾			Percentage of Net Credit Exposure

(in millions)

September 30, 2003
Investment grade ⁽³⁾		$	98	74%
Non-investment grade			35	26%

Total		$	133	100%




December 31, 2002
Investment grade ⁽³⁾		$	111	63%
Non-investment grade			64	37%

Total		$	175	100%




⁽¹⁾	Credit ratings are determined by using publicly available credit ratings of the counterparty. If the counterparty provides a guarantee by a higher rated entity (e.g., its parent), the rating determination is based on the rating of its 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 quality.

CRITICAL ACCOUNTING POLICIES

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

Derivatives and Energy Trading Activities

In 2001, PG&E Corporation and the Utility adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Hedging Activities" (collectively, SFAS No. 133), which required all derivative instruments to be recognized in the financial statements at their fair value. Prior to its rescission, PG&E Corporation accounted for its energy trading activities in accordance with Emerging Issues Task Force (EITF) No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and SFAS No. 133, which require certain energy trading contracts to be accounted for at fair values using mark-to-market accounting.

PG&E Corporation and the Utility have derivative commodity contracts for the physical delivery of purchase and sale quantities such as natural gas and electricity transacted in the normal course of business. These derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and are not reflected on the balance sheet at fair value. See further discussion in Notes 1 and 5 of the Notes to the Consolidated Financial Statements.

Unbilled and Surcharge 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 the actual load (energy) delivered with recent historical usage and rate patterns.

Since the CPUC authorized the collection of incremental surcharge revenues in January, March, and May 2001, the Utility has not provided reserves for potential refunds of these surcharges, nor would the surcharges be subject to refund under the proposed CPUC settlement agreement in the Utility's Chapter 11 proceeding. If the proposed CPUC settlement agreement is not approved, it is possible that subsequent decisions by the CPUC may affect the amount and timing of these surcharge revenues recovered by the Utility and that subsequent CPUC decisions may order the Utility to refund all or a portion of the surcharge revenues collected. See Note 2 of the Notes to the Consolidated Financial Statements and the risk factors discussion within the "Overview" section of this MD&A for further discussion.

DWR Revenues

The Utility acts as a pass-through entity for electricity purchased by the DWR on behalf of customers in the Utility's service area. Although charges for electricity provided by the DWR are included in the amounts the Utility bills its customers, the Utility deducts from electric revenues amounts passed through to the DWR. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers at the related CPUC-approved rate. These pass-through amounts are excluded from the Utility's electric revenues in its Consolidated Statements of Income.

The DWR's revenue requirements for 2001, 2002, 2003, and 2004 are subject to true-up adjustments to reflect actual data. Factors that could affect the amount of pass-through revenues recorded by the Utility include whether the CPUC revises or adjusts any of these DWR revenue requirements.

Depending on whether these revisions or adjustments or any other revisions are ultimately approved or disapproved by the CPUC, the outcome could have a material adverse effect on the Utility's results of operations or financial condition. See further discussion in "DWR Revenue Requirement" and "DWR Bond Charges" in the "Regulatory Matters" section of this MD&A.

Regulatory Assets and Liabilities

PG&E Corporation and the Utility apply SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), to their regulated operations. Under SFAS No. 71, regulatory assets represent capitalized costs that otherwise would be charged to expense under GAAP. These costs are later recovered through regulated rates. Regulatory liabilities are created by rate actions of a regulator that will later be credited to customers through the ratemaking process. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. If it is determined that these items are no longer likely to be recovered under SFAS No. 71, they will be written off at that time. At September 30, 2003, PG&E Corporation reported regulatory assets of $2.2 billion, including current regulatory balancing accounts receivable, and regulatory liabilities of $1.1 billion, including current regulatory balancing accounts payable.

Environmental Remediation Liabilities

The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and the cost can be reasonably estimated. This liability is based on site investigations, remediation, operations, maintenance, monitoring, and closure. This liability is reviewed on a quarterly basis and is recorded at the lower range of estimated costs, unless there is a better estimate available. At September 30, 2003, the Utility's undiscounted environmental remediation liability was $323 million. The Utility's future cost could increase to as much as $418 million if (1) the other potentially responsible parties are not financially able to contribute to these costs, (2) the extent of contamination or necessary remediation is greater than anticipated, or (3) the Utility is found to be responsible for clean-up costs at additional sites.

The process of estimating remediation liabilities is difficult and changes in the estimate could occur, given the uncertainty concerning the Utility's ultimate liability, the complexity of environmental laws and regulations, the selection of compliance alternatives, and the financial resources of other responsible parties.

The Utility's Chapter 11 Filing

Due to the Utility's Chapter 11 filing in 2001, the financial statements for both PG&E Corporation and the Utility are prepared in accordance with SOP 90-7, which is used by reorganizing entities operating under the Bankruptcy Code. Under SOP 90-7, certain claims against the Utility prior to its Chapter 11 filing are classified as Liabilities Subject to Compromise. The Utility reported a total of $9.5 billion of Liabilities Subject to Compromise at September 30, 2003. While the Utility operates under the protection of the Bankruptcy Court, the realization of assets and the liquidation of liabilities is subject to uncertainty, as additional claims to Liabilities Subject to Compromise can change due to such actions as the resolution of disputed claims or certain Bankruptcy Court actions. See Note 2 of the Notes to the Consolidated Financial Statements for further discussion of the status of the Utility's Chapter 11 proceeding.

See Note 1 of the Notes to the Consolidated Financial Statements for further discussion of accounting policies and new accounting developments.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Consolidation of Variable Interest Entities

The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by PG&E Corporation or the Utility between February 1, 2003, and September 30, 2003. PG&E Corporation and the Utility must apply the provisions of FIN 46 as of December 31, 2003, for entities created prior to February 1, 2003.

PG&E Corporation and the Utility are continuing to evaluate the impacts of FIN 46's initial recognition, measurement, and disclosure provisions on the consolidated financial statements and are unable to estimate the impact, if any, which will result when FIN 46 becomes effective. The Utility has investments in unconsolidated affiliates, which are mainly engaged in the purchase of residential real estate property. It is reasonably possible that the Utility will be required to consolidate its interests in two of these entities as a result of the adoption of FIN 46. At September 30, 2003, the Utility's recorded investment in these entities is approximately $17 million. As a limited partner, the Utility's exposure to potential loss is limited to its investment in each partnership.

Changes to Accounting for Certain Derivative Contracts

In June 2003, the Financial Accounting Standards Board (FASB) issued a new Derivatives Implementation Group (DIG) interpretation of SFAS No. 133, Issue No. C20, "Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature" (DIG C20). DIG C20 specifies additional circumstances under which price adjustment features, such as those based on broad market indices, in a derivative contract would not be an impediment to qualify for the normal purchases and normal sales scope exception under SFAS No. 133. One of the attributes necessary to qualify for the normal purchases and sales exception is that the pricing must be deemed to be clearly and closely related to the asset to be delivered under the contract. Under DIG C20, as long as the price adjustment feature in a contract is expected to be highly correlated to the asset to be delivered under that contract, the use of a broad market index (such as the consumer price index) as a price adjustment feature is considered clearly and closely related. Previously, under DIG C11, "Interpretations of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exceptions," the use of a price adjustment based on a broad market index was not considered to be clearly and closely related to the asset to be delivered, and the contract was not eligible for the normal purchases and sales exception. The guidance in DIG C11 is superseded by DIG C20.

TAXATION MATTERS

The Internal Revenue Service (IRS) has completed its audit of PG&E Corporation's 1997 and 1998 consolidated U.S. federal income tax returns and has assessed additional federal income taxes of $73 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. The IRS also is auditing PG&E Corporation's 1999 and 2000 consolidated U.S. federal income tax returns, but has not issued its final report. However, the IRS has proposed adjustments totaling $69 million (including interest).

As a result of NEGT, Inc.'s Chapter 11 filing on July 8, 2003, the IRS recently began its audit of PG&E Corporation's 2001 and 2002 consolidated U.S. federal income tax returns. Under applicable bankruptcy law, the IRS has 180 days from the date of the filing of the petition to submit its proof of claim to the Bankruptcy Court. All of PG&E Corporation's federal income tax returns prior to 1997 have been closed. In addition, California and certain other state tax authorities currently are auditing various state tax returns. On June 27, 2003, the IRS announced it will review scientific tests related to production of synthetic fuels (Section 29); NEGT, Inc. operated two synthetic fuel facilities in 2001 and most of 2002. The aggregate amount claimed for these Section 29 credits was approximately $104 million. The resolution of these matters with the IRS is not expected to have a material adverse effect on PG&E Corporation's earnings.

In addition, PG&E Corporation recognized federal deferred tax assets related to losses incurred at NEGT, Inc. These deferred tax assets were determined on a consolidated basis, with the related tax benefit of zero and $157 million recorded in discontinued operations, zero and $3 million recorded in cumulative effect of changes in accounting principles, and zero and $44 million recorded in OCI for the three- and nine-month periods ended September 30, 2003.

ADDITIONAL SECURITY MEASURES

Various federal regulatory agencies have issued guidance and the Nuclear Regulatory Commission recently has issued orders regarding additional security measures to be taken at various facilities owned by PG&E Corporation and the Utility. Facilities of PG&E Corporation and the Utility affected by the guidance and the orders include generation facilities, transmission substations, and natural gas transportation facilities. The pending guidance may, and the current guidance and orders will require additional capital investment and an increased level of operating costs, some of which may not be recoverable through current regulatory mechanisms. However, neither PG&E Corporation nor the Utility believes these costs will have a material impact on their consolidated financial position or results of operations.

OTHER LONG-TERM CAPITAL EXPENDITURES

Steam Generator

During a routine inspection conducted as part of Diablo Canyon's last refueling of Unit 2, the Utility has found indications of steam generator tube cracking in locations not previously detected. Additional inspections of steam generators that the Utility now will need to perform at each refueling until the steam generators are replaced will lengthen future refueling outages. Therefore, the Utility now is planning to accelerate the replacement of steam generators, which is estimated to cost approximately $655 million for the two units combined, to 2008 and 2009 rather than 2009 as originally contemplated.

Path 15 Upgrade

In December 2002, the Utility agreed to participate in a project sponsored by Western Area Power Administration (WAPA) to upgrade the transfer capability of the section of transmission system known as Path 15, located in central California. The project entails construction of a new 84-mile, 500 kV transmission line by WAPA between two existing substations in northern and central California owned by the Utility and WAPA. All the participants have agreed to turn over operational control of the transmission system upgrade to the ISO upon completion of the project. The Utility's share of total costs of this project is approximately $75 million. The Utility's commitments are contingent upon WAPA meeting certain construction milestones.

UTILITY CUSTOMER INFORMATION SYSTEM

The Utility implemented a new customer information system at the end of 2002 and continues to work through various billing and collection issues associated with the change over to the new system. The implementation has, among other things, required the Utility to put into place new processes for recording and estimating revenues and electricity-related costs. The Utility does not expect the system changes to have a significant impact on its financial position and 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.

OTHER MATTERS

The Boards of Directors of PG&E Corporation and the Utility each has determined that both C. Lee Cox and Barry Lawson Williams, members of each company's Audit Committee, are "audit committee financial experts" as defined by the Securities and Exchange Commission regulations, implementing Section 407 of the Sarbanes-Oxley Act of 2002. Each Board of Directors has determined that Messrs. Cox and Williams are "independent" as defined by current listing standards of the New York Stock Exchange and the American Stock Exchange, as applicable.

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation's and Pacific Gas and Electric Company's (the Utility) primary market risk results from changes in energy prices and interest rates. PG&E Corporation and the Utility engage in price risk management (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 the Utility's disclosure controls and procedures as of September 30, 2003, 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.

There were no changes in internal controls over financial reporting that occurred during the quarter ended September 30, 2003, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's controls over financial reporting.

During the first quarter of 2003, PG&E National Energy Group, Inc. (PG&E NEG) management discovered misclassifications of certain offsetting revenues and expenses between discontinued operations and continuing operations of a subsidiary of PG&E NEG, which netted to zero. As a result of PG&E NEG's Chapter 11 filing on July 8, 2003, the resignation of PG&E Corporation's representatives who previously served on PG&E NEG's Board of Directors, and their replacement with Board members elected by PG&E NEG who are not affiliated with PG&E Corporation, PG&E Corporation no longer retains significant influence over the ongoing operations of PG&E NEG. On October 3, 2003, the Bankruptcy Court authorized PG&E NEG to change its name to National Energy and Gas Transmission, Inc. (NEGT, Inc.). The change reflects NEGT, Inc.'s pending separation from PG&E Corporation. Consequently, all subsequent references to PG&E NEG will refer to NEGT, Inc. However, PG&E Corpo ration has been informed that subsequent to the end of the second quarter, NEGT, Inc. has initiated appropriate actions and controls designed to prevent recurrence of the types of errors that led to the misclassifications.

NEGT, Inc. reviewed its second quarter presentation methods for netting certain trading and hedging revenues and expenses. NEGT, Inc. adopted a net presentation approach for such transactions and reflected this change in its second quarter results. For prior periods, NEGT, Inc. continues to review this matter, which generally arises as the result of changes made in 2002 to the presentation of trading and hedging revenues and expenses to reflect the netting of certain trading activities and the reclassification of discontinued operations. PG&E Corporation cannot predict the results of this review, but does not believe that it will have any impact to net income. This review could result in additional changes in revenues and expenses of discontinued operations for prior periods.

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 Consolidated Financial Statements.

Pacific Gas and Electric Company Chapter 11 Filing

Pacific Gas and Electric Company's (Utility) Chapter 11 proceeding has been previously disclosed in PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.

On June 19, 2003, PG&E Corporation, the Utility, and the staff of the California Public Utilities Commission (CPUC) announced a proposed settlement agreement that contemplates a new plan of reorganization (Settlement Plan). The proposed CPUC settlement agreement is subject to the approval of the Boards of Directors of PG&E Corporation and the Utility, as well as the CPUC. In addition, the proposed CPUC settlement agreement must be executed by all parties on or before December 31, 2003. On July 25, 2003, the Utility filed its testimony in support of the proposed CPUC settlement agreement. Testimony from the staff of the CPUC and the Official Committee of Unsecured Creditors (OCC) was also filed on July 25, 2003. On September 25, 2003, the Utility and 22 other organizations representing federal, state, and local governments, environmental groups, resource conservation, and agricultural and water interests entered into a comprehensive stipulation that resolves most, if not all, of the environmen tal issues pertaining to the proposed settlement agreement. While the stipulation does not change the proposed CPUC settlement agreement in any way, it establishes mutually agreeable procedures for implementing the proposed CPUC settlement agreement's proposed land conservation commitment, under which the Utility will either provide conservation easements or donate to public agencies or conservation organizations approximately 140,000 acres of watershed and other lands.

The CPUC concluded the public evidentiary hearings on the proposed CPUC settlement agreement on September 26, 2003. The CPUC is currently expected to vote on the proposed CPUC settlement agreement in late December 2003.

In addition, the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court) must confirm the Settlement Plan. While the CPUC is not a proponent, it would agree under the proposed CPUC settlement agreement to support the Settlement Plan. On August 15, 2003, a disclosure statement and ballot were sent to creditors entitled to vote on the Settlement Plan. Solicitation of creditor votes ended on September 29, 2003. On October 14, 2003, the Utility filed the voting results with the Bankruptcy Court. All of the creditor classes that voted on the Settlement Plan voted in favor of the Settlement Plan.

On September 26, 2003, the State of California filed a motion for summary judgment in the Bankruptcy Court, seeking an order finding that the Settlement Plan cannot be confirmed because it illegally releases or discharges third-party claims against PG&E Corporation and its officers and directors, including the claims brought by the California Attorney General (AG) and the City and County of San Francisco (CCSF) under Section 17200 of the California Business & Professions Code, without the third parties' express consent. PG&E Corporation and the Utility believe that the Settlement Plan does not attempt to obtain the release or discharge of claims other than as allowed by law. The Bankruptcy Court heard the State's summary judgment motion on October 16, 2003, but has not ruled on the motion.

The Bankruptcy Court confirmation hearing began on November 10, 2003. Various confirmation trial dates have been set for November and December 2003, the latest of which is December 18, 2003. Trial briefs in opposition to the Settlement Plan were filed by, among others, the State of California, CCSF, and various municipalities. Among other arguments, the State of California and CCSF reassert the argument made by the State of California in its summary judgment motion; namely, that the Settlement Plan's proposed release and discharge provisions are overbroad and are intended to improperly release claims held by third parties against PG&E Corporation.

For more information about the Utility's Chapter 11 proceeding and the proposed settlement agreement, see "Management's Discussion and Analysis" and Note 2 of the Notes to the Consolidated Financial Statements.

PG&E Corporation and the Utility are unable to predict whether the proposed CPUC settlement agreement will be approved or whether the Settlement Plan will become effective or what the outcome of the Utility's Chapter 11 proceeding will be. If the proposed CPUC settlement agreement and the related Settlement Plan do not become effective, the Utility's financial condition and results of operations could be materially adversely affected due to the outcome of certain pending regulatory proceedings as discussed above in "Management's Discussion and Analysis" and Note 6 of the Notes to the Consolidated Financial Statements.

Chapter 11 Filing of National Energy & Gas Transmission, Inc. (formerly PG&E National Energy Group, Inc.)

For information regarding this matter, see PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, and Notes 1 and 4 of the Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company v. Loretta M. Lynch, et al.

For more information regarding the Filed Rate Case litigation, see "Part I, Item 3: Legal Proceedings - Pacific Gas and Electric Company vs. California Public Utilities Commissioners " in PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and "Part II, Item 1: Legal Proceedings - Pacific Gas and Electric Company vs. California Public Utilities Commissioners " of PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2003.

Federal Securities Lawsuit

As previously disclosed in PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, on June 10, 2003, the Ninth Circuit heard oral argument on plaintiffs' appeal of the District Court's order dismissing the second amended complaint with prejudice. In July 2003, the Ninth Circuit court upheld the District Court's dismissal of the plaintiffs' second amended complaint, finding that the plaintiffs had failed to establish that PG&E Corporation's Consolidated Financial Statements for the second and third quarters of 2000 were materially misleading. The plaintiffs have failed to appeal or take any further steps to pursue this matter.

For more information regarding this matter, see "Part I, Item 3: Legal Proceedings" of PG&E Corporation's 2002 Annual Report on Form 10-K, as amended.

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 2002 Annual Report on Form 10-K, as amended.

Moss Landing Power Plant

For information regarding this matter, see PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, 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 June 30, 2003.

Diablo Canyon Power Plant

For information regarding this matter, see PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and "Part II, Item 1: Legal Proceedings" of PG&E Corporation's and the Utility's combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.

Compressor Station Chromium Litigation

As previously disclosed in PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and the combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, as amended, the Utility has filed 13 summary judgment motions challenging the claims of the trial test plaintiffs in the Chromium Litigation. Two of these motions are scheduled to be heard in December 2003 and two of these motions are scheduled to be heard in January 2004. The Utility also has filed a motion to dismiss the complaint in one of the cases that is scheduled to be heard on November 14, 2003. The trial of 18 test cases has been scheduled to begin in March 2004.

California Energy Trading Litigation

For information regarding these matters, see PG&E Corporation's 2002 Annual Report on Form 10-K, as amended, and PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003.

California Attorney General Complaint

As previously disclosed in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, on July 24, 2003, the U.S. District Court for the Northern District of California (District Court) heard oral argument on the appeal and cross-appeal of the Bankruptcy Court's remand order. On October 8, 2003, the District Court reversed, in part, the Bankruptcy Court's June 2002 decision and ordered the AG restitution claims sent back to the Bankruptcy Court. The District Court found that these claims, estimated along with the City and County of San Francisco's claims discussed below at approximately $5 billion, are the property of the Utility's Chapter 11 estate and therefore are properly within the Bankruptcy Court's jurisdiction. Under the Settlement Plan, the Utility would release these claims. The District Court also affirmed, in part, the Bankruptcy Court's June 2002 decision and found that the AG's civil penalty and injunctive relief claims under California's Business and Professions Code (Section 17200) could be resolved in San Francisco Superior Court, where a status conference has been scheduled for December 18, 2003. No proceedings have been scheduled in Bankruptcy Court regarding the restitution claims. Under Section 17200, the AG is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. The AG's complaint asserted that the total civil penalties would be not less than $500 million. PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.

For more information regarding this matter, see "Part I, Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and the combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.

Complaint Filed by the City and County of San Francisco and the People of the State of California

As previously disclosed in PG&E Corporation's and the Utility's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, on July 24, 2003, the District Court heard oral argument on the appeal and cross appeal of the Bankruptcy Court's remand order. On October 8, 2003, the District Court reversed, in part, the Bankruptcy Court's June 2002 decision and ordered the City and County of San Francisco (City)'s restitution claims sent back to the Bankruptcy Court. The District Court found that these claims, estimated along with the AG's claims discussed above at approximately $5 billion, are the property of the Utility's Chapter 11 estate and therefore are properly within the Bankruptcy Court's jurisdiction. Under the Settlement Plan, the Utility would release these claims. The District Court also affirmed, in part, the Bankruptcy Court's June 2002 decision and found that the City's civil penalty and injunctive relief claims under Section 17200 could be resolved in San Francisco Su perior Court, where a status conference has been scheduled for December 18, 2003. No proceedings have been scheduled in Bankruptcy Court regarding the restitution claims. Under Section 17200, the City is entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.

For more information regarding this matter, see "Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.

Cynthia Behr v. PG&E Corporation, et al.

For more information regarding this matter, see "Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and the combined Quarterly Reports on Form 10-Q for the quarters ended March 31, 2003, as amended, and June 30, 2003.

PG&E Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its financial condition or results of operations.

PG&E National Energy Group's Brayton Point Generating Station

For information regarding this matter, see PG&E Corporation's 2002 Annual Report on Form 10-K, as amended.

William Ahern, et al. v. Pacific Gas and Electric Company

For more information regarding this matter, see "Item 3: Legal Proceedings" of PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, and the combined Quarterly Report for the Form 10-Q for the quarter ended March 31, 2003, as amended.

ITEM 2: CHANGES IN SECURITIES AND USE OF PROCEEDS

On July 2, 2003, PG&E Corporation completed a private placement of $600 million of 6⅞ percent Senior Secured Notes due 2008 (Notes). The Notes are secured by a pledge of approximately 94 percent of the outstanding common stock of the Utility. The Notes are effectively subordinated to all indebtedness and other obligations of PG&E Corporation's subsidiaries. The indenture, dated as of July 2, 2003, will permit PG&E Corporation and its subsidiaries to incur additional indebtedness, including secured equal ranking indebtedness.

The net proceeds of the offering, together with cash on hand, were used to pay approximately $735 million under PG&E Corporation's existing credit agreement, including outstanding principal, all accrued interest, and prepayment premiums. The payment also resulted in the termination of PG&E Corporation's existing credit agreement and the release of liens on PG&E Corporation's shares of PG&E National Energy Group, LLC and on PG&E National Energy Group, LLC shares of National Energy & Gas Transmission, Inc. (formerly PG&E National Energy Group, Inc.).

The Notes were offered within the United States only to qualified institutional investors pursuant to Rule 144A under the Securities Act of 1933 (Securities Act) and, outside the United States, only to non-U.S. investors. The offer and sale of the Notes have not been registered under the Securities Act, or under any state securities laws, and the Notes may not be offered or sold in the United States absent registration or an applicable exemption from registration requirements under the Securities Act and applicable state securities laws.

PG&E Corporation has agreed to file a registration statement with the Securities and Exchange Commission relating to an offer to exchange the Notes for publicly tradable notes having substantially identical terms to the Notes. In addition, PG&E Corporation may be required to file a shelf registration statement covering resales of the Notes.

ITEM 3: DEFAULTS UPON SENIOR SECURITIES

At the time of 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 has been in default 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, resulting in loans from the banks to the Utility, which have not been paid. 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 has made past-due and current interest payments 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 has paid past-due interest advances and is paying current 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 has occurred under the relevant loan agreements with the California Pollution Control Financing Authority due to the Utility's Chapter 11 filing. However, the Utility has obtained Bankruptcy Court approval to make regular payments on its mortgage bonds and consequently the debt service payments on these bonds are passed through to the pollution control bondholders.

The Utility's filing of a Chapter 11 petition also constitutes a default under the indenture that governs its medium-term notes ($287 million aggregate amount outstanding), five-year 7.375 percent 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 has made past-due and current interest payments on its medium-term notes, its 7.375 percent 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.

The Utility has not made principal payments on unsecured long-term debt of $155 million.

With regard to the 7.90 percent Quarterly Income Preferred Securities (QUIPS) and the related 7.90 percent Deferrable Interest Debentures (Debentures), the Utility's filing of a Chapter 11 petition is 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 percent Deferrable Interest Subordinated Debentures (QUIDS). As authorized by the Bankruptcy Court, starting in May 2002, the Utility has made past-due and current interest payments on the QUIDS. See Note 2 of the Notes to the Consolidated Financial Statements for more information.

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 September 30, 2003, the Utility had issued and outstanding 5,784,825 shares of non-redeemable preferred stock and 5,973,456 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 3 million shares of the 6.57 percent series and 2.5 million shares of the 6.30 percent series at September 30, 2003. At the Utility's option, the 6.57 percent series may be redeemed beginning 2002 and the 6.30 percent series may be redeemed beg inning 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 September 30, 2003, the redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions were $4 million per year for 2002, 2003, and 2004 for the 6.57 percent series, and $3 million per year beginning 2004 for the 6.30 percent series. The Utility is not permitted to make sinking fund payments unless all dividends on preferred stock have been paid. As discussed below, the Utility's Board of Directors has 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 percent 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 percent 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 percent, 5.5 percent, and 6.0 percent series of preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share.

Due to the California energy crisis and the Utility's pending Chapter 11 proceeding, the Utility's Board of Directors has not declared any preferred stock dividends since the dividend paid with respect to the three-month period ended October 31, 2000.

Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and equal preference in dividend and liquidation rights. Accumulated and unpaid dividends through September 30, 2003, amounted to $69.6 million. 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.

Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, there would be no restrictions on the ability of the Boards of Directors of the Utility or PG&E Corporation to declare and pay dividends or repurchase common stock, other than the capital structure and stand-alone dividend conditions contained in prior CPUC decisions authorizing the formation of the holding company. Further, the Utility would agree that it would not pay any dividend on its common stock before July 1, 2004.

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's earnings to fixed charges ratio for the nine months ended September 30, 2003, was 2.98. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, 2003, was 2.87. 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 Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959, relating to Pacific Gas and Electric Company's various classes of debt and first preferred stock outstanding.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)

4.1	Indenture dated as of July 2, 2003 by and between PG&E Corporation and Bank One, N.A. (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (File No. 1-12609), Exhibit 4.1)
4.2	Utility Stock Base Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (File No. 1-12609), Exhibit 4.2)
4.3	Utility Stock Protective Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (File No. 1-12609), Exhibit 4.3)
4.4	Form of 6⅞ percent Senior Secured Note due 2008 (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (File No. 1-12609), Exhibit 4.4)
11	Computation of Earnings Per Common Share
12.1	Computation of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

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

(b)	The following Current Reports on Form 8-K ⁽¹⁾ were filed, or furnished as indicated, during the third quarter of 2003 and through the date hereof:

1. July 2, 2003

         PG&E Corporation and NEGT, Inc.

Item 5.

Other Events

Extension of GenHoldings Transfer Date

Settlement of DTE/Georgetown Tolling Dispute

Item 7.

Financial Statements, Pro Forma Financial Information, and Exhibits

Exhibit 99.1 - Termination Agreement, dated as of June 24, 2003, by and between PG&E Energy Trading-Power, L.P., PG&E Gas Transmission, Northwest Corporation, and DTE Georgetown, LLC

2. July 2, 2003

         PG&E Corporation only

Item 5.

Other Events

Closing of Private Placement

Item 7.

Financial Statements, Pro Forma Financial Information, and Exhibits

Exhibit 4.1 - Indenture dated as of July 2, 2003 by and between PG&E Corporation and Bank One, N.A.

Exhibit 4.2 - Utility Stock Base Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas

Exhibit 4.3 - Utility Stock Protective Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas

Exhibit 4.4 - Form of 6⅞ percent Senior Secured Note due 2008

3. July 2, 2003

         PG&E Corporation only

Item 5.

Other Events

Press Release Regarding Closing of Private Placement

Item 7.

Financial Statements, Pro Forma Financial Information, and Exhibits

Exhibit 99 - Press release dated July 2, 2003

4. July 8, 2003

         PG&E Corporation only

Item 5.

Other Events

PG&E National Energy Group, Inc. Bankruptcy

5. July 8, 2003

Item 5.

Other Events

Proposed Settlement Agreement

Credit Ratings

Item 9.

Regulation FD Disclosure (furnished to the SEC)

Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended May 31, 2003 and Balance Sheet dated May 31, 2003

Exhibit 2 - Exhibit C to Disclosure Statement

6. August 14, 2003

Item 5.

Other Events

Inability to File Form 10-Q by August 14, 2003

7. August 19, 2003

Item 12.

Results of Operation and Financial Condition (furnished to SEC)

Release of Second Quarter Earnings Results

8. August 25, 2003

Item 5.

Other Events

California Supreme Court Decision

California Department of Water Resources' 2003 Revenue Requirement

9. September 3, 2003

Item 5.

Other Events

Settlement Conference in 2003 General Rate Case Proceeding

Item 9.

Regulation FD Disclosure (furnished to the SEC)

Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended July 31, 2003 and Balance Sheet dated July 31, 2003

10. September 10, 2003

Item 5.

Other Events

California Department of Water Resources' 2003 Revenue Requirement

Utility's Bankruptcy Proceeding

PG&E National Energy Group, Inc. Bankruptcy

11. September 16, 2003

Item 5.

Other Events

Pacific Gas and Electric Company's 2003 General Rate Case Proceeding

Item 9.

Regulation FD Disclosure (furnished to the SEC)

12.October 3, 2003

Item 9.

Regulation FD Disclosure (furnished to the SEC)

Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended August 31, 2003 and Balance Sheet dated August 31, 2003

13.October 15, 2003

Item 5.

Other Events

Item 9.

Regulation FD Disclosure (furnished to the SEC)

Exhibit 1 - Revised Financial Projections Relating to the Settlement Plan

14. October 24, 2003

Item 5.

Other Events

Credit Rating Change

Department of Water Resources' 2001-2002 Revenue Requirement True-Up Proceeding

15. November 12, 2003

Item 12.

Results of Operation and Financial Condition (furnished to the SEC)

Release of Third 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

/S/ CHRISTOPHER P. JOHNS

Christopher P. Johns

Senior Vice President and Controller

(duly authorized officer and principal accounting officer)

PACIFIC GAS AND ELECTRIC COMPANY

/S/ DINYAR B. MISTRY

Dinyar B. Mistry

Vice President and Controller

(duly authorized officer and principal accounting officer)

Dated: November 12, 2003

EXHIBIT INDEX

4.1

Indenture dated as of July 2, 2003, by and between PG&E Corporation and Bank One, N.A. (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.1)

4.2

Utility Stock Base Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.2)

4.3

Utility Stock Protective Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.3)

4.4

Form of 6⅞ percent Senior Secured Note due 2008 (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.4)

11

Computation of Earnings Per Common Share

12.1

Computation of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2

Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

31.1

Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2

Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

32.1*

Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

32.2*

Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

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

(in millions)	Amount Owed		Agreed Upon Interest Rate at September 30, 2003 (per annum)


Commercial Paper Claims	$	873	8.216%
Floating Rate Notes	1,240		8.333%
Senior Notes	680		10.375%
Medium-Term Notes	287		6.560% to 9.200%
Revolving Line of Credit Claims	938		8.750%
Pollution Control Bonds	814		1.230% to 5.350%
QFs	52		5.000%
Other Claims	4,617		3.100% to 12.000%

Liabilities Subject to Compromise at September 30, 2003	$	9,501

	Balance at

(in millions)	December 31, 2002

Assets
Total current assets	$			3,029
Net property, plant and equipment	2,939
Total other non-current assets	1,944

Total assets	7,912


Liabilities
Debt in default			4,230
Long-term debt, classified as current	17
Other current liabilities	2,410

Total current liabilities	6,657

Long-term debt	630
Price risk management	305
Other non-current liabilities and deferred credits		972

Total non-current liabilities		1,907

Total liabilities		8,564

Excess of liabilities over assets		$		(652)


(in millions)		Utility		PG&E Corporation, Eliminations and Other ⁽¹⁾			Total

Three months ended September 30, 2003
Operating revenues		$	3,103	$	-		$	3,103
Intersegment revenues		-		-			-

Total operating revenues		3,103		-			3,103
Income (Loss) from continuing operations ⁽²⁾		583		(75)			508
Net income (loss)⁽³⁾		583		(73)			510

Three months ended September 30, 2002
Operating revenues		2,947		-			2,947
Intersegment revenues		2		(2)			-

Total operating revenues		2,949		(2)			2,947
Income (Loss) from continuing operations ⁽²⁾		520		(41)			479
Net income (loss)⁽³⁾		520		(54)			466

Nine months ended September 30, 2003
Operating revenues		7,897		-			7,897
Intersegment revenues		3		(3)			-

Total operating revenues		7,900		(3)			7,897
Income (Loss) from continuing operations ⁽²⁾		844		(90)			754
Net income (loss)⁽³⁾		843		(460)			383

Nine months ended September 30, 2002
Operating revenues		8,108		-			8,108
Intersegment revenues		8		(8)			-

Total operating revenues		8,116		(8)			8,108
Income (Loss) from continuing operations ⁽²⁾		1,573		(41)			1,532
Net income (loss)⁽³⁾		1,573		(258)			1,315

Total assets at September 30, 2003		$	26,850	$		910	$	27,760

Total assets at September 30, 2002		$	24,942	$		11,693	$	36,635

⁽¹⁾	Includes PG&E Corporation, PG&E Ventures LLC, and elimination entries. PG&E Corporation's net income (loss) includes the results of NEGT, Inc.'s discontinued operations through July 7, 2003, and the elimination of $160 million for the nine-month period ended September 30, 2003, of deferred tax asset valuation reserves recorded at NEGT, Inc. PG&E Corporation believes it is more likely than not that it will be able to realize these deferred tax assets on a consolidated basis.
⁽²⁾	Corresponds to the Utility's Income Available for Common Stock excluding Cumulative Effect of a Change in Accounting Principle.
⁽³⁾	Corresponds to the Utility's Income Available for Common Stock.

1. July 2, 2003
PG&E Corporation and NEGT, Inc.
	Item 5.	Other Events
		Extension of GenHoldings Transfer Date
		Settlement of DTE/Georgetown Tolling Dispute
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 99.1 - Termination Agreement, dated as of June 24, 2003, by and between PG&E Energy Trading-Power, L.P., PG&E Gas Transmission, Northwest Corporation, and DTE Georgetown, LLC

2. July 2, 2003
PG&E Corporation only
	Item 5.	Other Events
		Closing of Private Placement
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 4.1 - Indenture dated as of July 2, 2003 by and between PG&E Corporation and Bank One, N.A.
		Exhibit 4.2 - Utility Stock Base Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas
		Exhibit 4.3 - Utility Stock Protective Pledge Agreement dated as of July 2, 2003 by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas
		Exhibit 4.4 - Form of 6⅞ percent Senior Secured Note due 2008

3. July 2, 2003
PG&E Corporation only
	Item 5.	Other Events
		Press Release Regarding Closing of Private Placement
	Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
		Exhibit 99 - Press release dated July 2, 2003

4. July 8, 2003
PG&E Corporation only
	Item 5.	Other Events
		PG&E National Energy Group, Inc. Bankruptcy

5. July 8, 2003	Item 5.	Other Events
		Proposed Settlement Agreement
		Credit Ratings
	Item 9.	Regulation FD Disclosure (furnished to the SEC)
		Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended May 31, 2003 and Balance Sheet dated May 31, 2003
		Exhibit 2 - Exhibit C to Disclosure Statement

6. August 14, 2003	Item 5.	Other Events
		Inability to File Form 10-Q by August 14, 2003

7. August 19, 2003	Item 12.	Results of Operation and Financial Condition (furnished to SEC)
		Release of Second Quarter Earnings Results

8. August 25, 2003	Item 5.	Other Events
		California Supreme Court Decision
		California Department of Water Resources' 2003 Revenue Requirement

9. September 3, 2003	Item 5.	Other Events
		Settlement Conference in 2003 General Rate Case Proceeding
	Item 9.	Regulation FD Disclosure (furnished to the SEC)
		Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended July 31, 2003 and Balance Sheet dated July 31, 2003

10. September 10, 2003	Item 5.	Other Events
		California Department of Water Resources' 2003 Revenue Requirement
		Utility's Bankruptcy Proceeding
		PG&E National Energy Group, Inc. Bankruptcy

11. September 16, 2003	Item 5.	Other Events
		Pacific Gas and Electric Company's 2003 General Rate Case Proceeding
	Item 9.	Regulation FD Disclosure (furnished to the SEC)

12.October 3, 2003	Item 9.	Regulation FD Disclosure (furnished to the SEC)
		Exhibit 1 - Pacific Gas and Electric Company Income Statement for the month ended August 31, 2003 and Balance Sheet dated August 31, 2003

13.October 15, 2003	Item 5.	Other Events
	Item 9.	Regulation FD Disclosure (furnished to the SEC)
		Exhibit 1 - Revised Financial Projections Relating to the Settlement Plan

14. October 24, 2003	Item 5.	Other Events
		Credit Rating Change
		Department of Water Resources' 2001-2002 Revenue Requirement True-Up Proceeding

15. November 12, 2003	Item 12.	Results of Operation and Financial Condition (furnished to the SEC)
		Release of Third Quarter Earnings Results

4.1	Indenture dated as of July 2, 2003, by and between PG&E Corporation and Bank One, N.A. (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.1)
4.2	Utility Stock Base Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.2)
4.3	Utility Stock Protective Pledge Agreement dated as of July 2, 2003, by and among PG&E Corporation, Bank One, N.A. and Deutsche Bank Trust Company Americas (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.3)
4.4	Form of 6⅞ percent Senior Secured Note due 2008 (incorporated by reference to PG&E Corporation's Form 8-K filed July 2, 2003 (file No. 1-12609), Exhibit 4.4)
11	Computation of Earnings Per Common Share
12.1	Computation of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002