10-Q

(Mark One)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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)				(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, August 13, 2003:
PG&E Corporation			412,035,998 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 JUNE 30, 2003
TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION			PAGE
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Operations		3
		Condensed Consolidated Balance Sheets		5
		Condensed Consolidated Statements of Cash Flows		7
	Pacific Gas and Electric Company, A Debtor-In-Possession
		Condensed Consolidated Statements of Income		9
		Condensed Consolidated Balance Sheets		10
		Condensed Consolidated Statements of Cash Flows		12
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		General	13
	NOTE 2:		Utility Chapter 11 Filing	22
	NOTE 3:		PG&E NEG Chapter 11 Filing	28
	NOTE 4:		Discontinued Operations and Assets Held for Sale	32
	NOTE 5:		Price Risk Management	34
	NOTE 6:		Commitments and Contingencies	39
	NOTE 7:		Segment Information	54
	NOTE 8:		Employee Benefit Plans	57
	NOTE 9:		Subsequent Events	57
ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			58
	Liquidity and Financial Resources			61
	Commitments and Capital Expenditures			69
	Cash Flows			70
	Results of Operations			75
	Regulatory Matters			83
	Risk Management Activities			91
	Critical Accounting Policies			99
	Accounting Pronouncements Issued But Not Yet Adopted			101
	Taxation Matters			102
	Additional Security Measures			103
	Other Long-Term Capital Expenditures			103
	Utility Customer Information System			103
	Employee Benefit Plans			103
	Environmental and Legal Matters			104
	Other Matters			104
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			105
ITEM 4.	CONTROLS AND PROCEDURES			105
PART II.	OTHER INFORMATION			106
ITEM 1.	LEGAL PROCEEDINGS			106
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES			111
ITEM 5.	OTHER INFORMATION			112
ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K			112
SIGNATURES				116

PART I. FINANCIAL INFORMATION
ITEM 1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)					(Unaudited)
					Three months ended					Six months ended
					June 30,					June 30,
					2003		2002			2003		2002
Operating Revenues							(as revised see Note 1)					(as revised see Note 1)
		Utility			$	2,730	$		2,714	$	4,797	$	5,167
		Energy commodities and services			196		223			430		443
				Total operating revenues	2,926		2,937			5,227		5,610
Operating Expenses
		Cost of electricity and natural gas for utility			835		703			1,862		852
		Cost of energy commodities and services			55		86			114		131
		Depreciation, amortization, and decommissioning			325		317			649		619
		Operating and maintenance			913		765			1,698		1,624
		Impairments, write-offs, and other charges			30		265			230		265
		Reorganization professional fees and expenses			65		18			100		34
				Total operating expenses	2,223		2,154			4,653		3,525
Operating Income					703		783			574		2,085
		Reorganization interest income			17		19			27		41
		Interest income			8		13			12		23
		Interest expense			(364)		(360)			(739)		(694)
		Other income (expense), net			-		(17)			3		3
Income (Loss) Before Income Taxes					364		438			(123)		1,458
		Income tax provision (benefit)			145		159			(64)		555
Income (Loss) From Continuing Operations					219		279			(59)		903
Discontinued Operations
	Earnings (loss) from operations of assets held for sale
			(net of income tax expense (benefit) of zero million and $(35) million for the three and six months ended June 30, 2003, and $(3) million and $2 million for the three and six months ended June 30, 2002)
					(4)		-			(69)		7
	Net gain on disposal of assets held for sale
			(net of income tax expense of $2 million and zero million for the three and six months ended June 30, 2003)
					12		-			7		-
Net Income (Loss) Before Cumulative Effect of Changes
	in Accounting Principles				227		279			(121)		910
	Cumulative effect of changes in accounting principles
			(net of income tax (benefit) of zero million and $(4) million for the three and six months ended June 30, 2003, and $(42) million for the three and six months ended June 30, 2002)		-		(61)			(6)		(61)
Net Income (Loss)					$	227	$	218		$	(127)	$	849
Weighted Average Common Shares Outstanding, Basic					384		366			383		365
Earnings (Loss) Per Common Share
	from Continuing Operations, Basic				$	0.57	$	0.76		$	(0.15)	$	2.48
Net Earnings (Loss) Per Common Share, Basic					$	0.59	$	0.60		$	(0.33)	$	2.33
Earnings (Loss) Per Common Share
	from Continuing Operations, Diluted				$	0.54	$	0.75		$	(0.15)	$	2.44
Net Earnings (Loss) Per Common Share, Diluted					$	0.56	$	0.59		$	(0.33)	$	2.29
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
				Balance at
				June 30,		December 31,
				2003 (Unaudited)		2002
ASSETS
Current Assets
	Cash and cash equivalents			$	4,864	$	3,895
	Restricted cash			915		708
	Accounts receivable:
		Customers (net of allowance for doubtful accounts of
			$109 million in 2003 and $113 million in 2002)	2,062		2,747
		Regulatory balancing accounts		142		98
	Price risk management			280		498
	Inventories			357		347
	Assets held for sale			454		707
	Prepaid expenses and other			269		472
		Total current assets		9,343		9,472
Property, Plant and Equipment
	Utility			28,298		27,045
	Non-utility:
		Electric generation		841		606
		Gas transmission		1,781		1,761
	Construction work in progress			1,332		1,560
	Other			182		177
		Total property, plant and equipment		32,434		31,149
	Accumulated depreciation and decommissioning			(13,462)		(14,245)
		Net property, plant and equipment		18,972		16,904
Other Noncurrent Assets
	Regulatory assets			1,957		2,053
	Nuclear decommissioning funds			1,410		1,335
	Price risk management			307		398
	Deferred income taxes			605		657
	Assets held for sale			814		940
	Other			1,100		1,937
		Total other noncurrent assets		6,193		7,320
TOTAL ASSETS				$	34,508	$	33,696
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions except share amounts)			Balance at
			June 30,			December 31,
			2003 (Unaudited)			2002
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
	Debt in default		$		4,691	$	4,230
	Long-term debt, classified as current		602			298
	Current portion of rate reduction bonds		290			290
	Accounts payable:
		Trade creditors	777			1,273
		Regulatory balancing accounts	214			360
		Other	737			660
	Interest payable		172			139
	Income taxes payable		336			129
	Price risk management		227			506
	Liabilities of operations held for sale		528			699
	Other		616			685
		Total current liabilities	9,190			9,269
Noncurrent Liabilities
	Long-term debt		4,034			4,345
	Rate reduction bonds		1,019			1,160
	Asset retirement obligations		1,398			-
	Deferred income taxes		1,521			1,439
	Deferred tax credits		135			144
	Price risk management		274			305
	Liabilities of operations held for sale		756			793
	Other		2,931			2,963
		Total noncurrent liabilities	12,068			11,149
Liabilities Subject to Compromise
	Financing debt		5,604			5,605
	Trade creditors		3,669			3,580
		Total liabilities subject to compromise	9,273			9,185
Commitments and Contingencies (Notes 1, 2, 3, and 6)			-			-
Preferred Stock of Subsidiaries			480			480
Common Shareholders' Equity
	Common stock, no par value, authorized 800,000,000 shares, issued
		409,038,465 common and 1,579,660 restricted shares in 2003 and 405,486,015 common shares in 2002		6,354		6,274
	Common stock held by subsidiary, at cost, 23,815,500 shares		(690)			(690)
	Unearned compensation		(22)			-
	Accumulated deficit		(2,005)			(1,878)
	Accumulated other comprehensive loss		(140)			(93)
		Total common shareholders' equity	3,497			3,613
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$		34,508	$	33,696
See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
						(Unaudited)
						Six months ended
						June 30,
						2003		2002
Cash Flows From Operating Activities
		Net income (loss)				$	(127)	$	849
		Adjustments to reconcile net income (loss) to
			net cash provided by operating activities:
					Depreciation, amortization, and decommissioning	649		656
					Amortization of deferred financing costs	47		12
					Deferred income taxes and tax credits, net	(153)		(178)
					Reversal of ISO accrual (Note 2)	-		(970)
					Price risk management assets and liabilities, net	(48)		238
					Other deferred charges and noncurrent liabilities	335		391
					Gain on impairment or disposal of assets	230		265
					Loss from discontinued operations	(7)		-
					Cumulative effect of changes in accounting principles	10		61
		Net effect of changes in operating assets and liabilities:
				Restricted cash		(207)		-
				Accounts receivable		633		(55)
				Inventories		(10)		18
				Accounts payable		(280)		335
				Accrued taxes		207		439
				Regulatory balancing accounts, net		(190)		(47)
				Other working capital		151		(168)
		Payments authorized by the Bankruptcy Court on amounts classified as     liabilities subject to compromise (Note 2)				(62)		(947)
		Assets and liabilities of operations held for sale, net				(4)		18
		Other, net				435		(505)
Net cash provided by operating activities						1,609		412
Cash Flows From Investing Activities
	Capital expenditures					(910)		(1,680)
	Net proceeds from disposal of discontinued operations					102		-
	Net proceeds from sale of asset					11		-
	Proceeds from sale-lease back					-		340
	Other, net					45		122
Net cash used by investing activities						(752)		(1,218)
Cash Flows From Financing Activities
	Net borrowings under debt in default					224		-
	Long-term debt issued					9		1,560
	Long-term debt matured, redeemed, or repurchased					(34)		(1,081)
	Rate reduction bonds matured					(141)		-
	Common stock issued					54		61
	Other, net					-		(37)
Net cash provided by financing activities						112		503
Net change in cash and cash equivalents						969		(303)
Cash and cash equivalents at January 1						3,895		5,355
Cash and cash equivalents at June 30						$	4,864	$	5,052

Supplemental disclosures of cash flow information
	Cash received for:
		Reorganization interest income	$	21	$	42
	Cash paid for:
		Interest (net of amounts capitalized)		432		874
		Income taxes paid (refunded), net	(531)		294
		Reorganization professional fees and expenses	71		9
Supplemental disclosures of noncash investing and financing activities
	Transfer of liabilities and other payables subject to compromise    from operating assets and liabilities		127		(475)
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in millions)
					(Unaudited)
					Three months ended				Six months ended
					June 30,				June 30,
					2003		2002		2003			2002
Operating Revenues
	Electric				$	2,062	$	2,193	$	3,299		$	3,971
	Natural gas				668		521		1,498			1,196
			Total operating revenues		2,730		2,714		4,797			5,167
Operating Expenses
	Cost of electricity				515		505		1,056			339
	Cost of natural gas				320		198		806			513
	Operating and maintenance				768		640		1,426			1,409
	Depreciation, amortization, and decommissioning				307		294		605			565
	Reorganization professional fees and expenses				65		18		100			34
			Total operating expenses		1,975		1,655		3,993			2,860
Operating Income					755		1,059		804			2,307
	Reorganization interest income				17		19		27			41
	Interest income				3		-		4			-
	Interest expense (noncontractual interest expense of $35   million and $67 million for the three and six months ended   June 30, 2003, and $54 million and $103 million for the   three and six months ended June 30, 2002)				(224)		(283)		(444)			(546)
	Other income (expense), net				3		(1)		7			(6)
Income Before Income Taxes					554		794		398			1,796
	Income tax provision				209		325		125			731
Income Before Cumulative Effect of a Change in    Accounting Principle					345		469		273			1,065
		Cumulative effect of change in accounting principle
				(net of income tax (benefit) of $(1) million for the six months ended June 30, 2003)	-		-		(1)			-
Net Income					345		469		272			1,065
	Preferred dividend requirement				6		6		12			12
Income Available for Common Stock					$	339	$	463	$		260	$	1,053
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
					Balance at
					June 30,		December 31,
					2003 (Unaudited)		2002
ASSETS
Current Assets
		Cash and cash equivalents			$	3,700	$	3,343
		Restricted cash			234		150
		Accounts receivable:
			Customers (net of allowance for doubtful accounts of
				$62 million in 2003 and $59 million in 2002)	1,763		1,900
			Related parties		18		17
			Regulatory balancing accounts		142		98
		Inventories:
			Gas stored underground and fuel oil		193		154
			Materials and supplies		124		121
		Prepaid expenses			72		110
		Other			11		55
			Total current assets		6,257		5,948
Property, Plant and Equipment
	Electric				20,053		18,922
	Gas				8,245		8,123
	Construction work in progress				321		427
			Total property, plant and equipment		28,619		27,472
	Accumulated depreciation and decommissioning				(12,706)		(13,515)
			Net property, plant and equipment		15,913		13,957
Other Noncurrent Assets
		Regulatory assets			1,922		2,011
		Nuclear decommissioning funds			1,410		1,335
		Other			511		1,300
			Total other noncurrent assets		3,843		4,646
TOTAL ASSETS					$	26,013	$	24,551
See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions except share amounts)
				Balance at
				June 30,		December 31,
				2003 (Unaudited)		2002
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
	Long-term debt, classified as current			$	591	$	281
	Current portion of rate reduction bonds			290		290
	Accounts payable:
		Trade creditors		460		380
		Related parties		191		130
		Regulatory balancing accounts		214		360
		Other		369		374
	Interest payable			148		126
	Income taxes payable			51		-
	Deferred income taxes			90		-
	Other			458		625
		Total current liabilities		2,862		2,566
Noncurrent Liabilities
	Long-term debt			2,429		2,739
	Rate reduction bonds			1,019		1,160
	Regulatory liabilities			939		1,461
	Asset retirement obligations			1,395		-
	Deferred income taxes			1,464		1,485
	Deferred tax credits			135		144
	Other			1,783		1,274
		Total noncurrent liabilities		9,164		8,263
Liabilities Subject to Compromise
	Financing debt			5,604		5,605
	Trade creditors			3,852		3,786
		Total liabilities subject to compromise		9,456		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	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		1,065			805
	Accumulated other comprehensive loss		(60)			-
		Total shareholders' equity	4,394			4,194
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY			$		26,013	$	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
(in millions)					(Unaudited)
						Six months ended
						June 30,
						2003			2002
Cash Flows From Operating Activities
	Net income					$	272		$	1,065
	Adjustments to reconcile net income to
			net cash provided by operating activities:
				Depreciation, amortization, and decommissioning		605			565
				Deferred income taxes and tax credits, net		101			(123)
				Other deferred charges and noncurrent liabilities		284			363
				Gain on sale of assets		(7)			-
				Reversal of ISO accrual		-			(970)
				Cumulative effect of changes in accounting principles		2			-
	Net effect of changes in operating assets and liabilities:
		Restricted cash				(84)		(1)
		Accounts receivable				84			99
		Inventories				(42)			47
		Accounts payable				252			97
		Income taxes payable				51			493
		Regulatory balancing accounts, net				(190)			(47)
		Other working capital				(79)			(34)
		Payments authorized by the Bankruptcy Court on amounts
		classified as liabilities subject to compromise (Note 2)				(62)			(947)
	Other, net					17			23
Net cash provided by operating activities						1,204			630
Cash Flows From Investing Activities
	Capital expenditures					(730)			(743)
	Net proceeds from sale of assets					11			5
	Other, net					13			13
Net cash used by investing activities						(706)			(725)
Cash Flows From Financing Activities
	Long-term debt matured, redeemed, or repurchased					-			(333)
	Rate reduction bonds matured					(141)			(141)
	Other, net					-			(1)
Net cash used by financing activities						(141)			(475)
Net change in cash and cash equivalents						357			(570)
Cash and cash equivalents at January 1						3,343			4,341
Cash and cash equivalents at June 30						$	3,700		$	3,771
Supplemental disclosures of cash flow information
	Cash received for:
		Reorganization interest income				$	21		$	42
	Cash paid for:
		Interest (net of amounts capitalized)				341			683
		Income taxes paid (refunded), net				(32)			353
		Reorganization professional fees and expenses				71			9
Supplemental disclosures of noncash investing and financing activities
	Transfer of liabilities and other payables subject to
		compromise (to) from operating assets and liabilities, net				127			(297)
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 was incorporated in California in 1995 and became the holding company of Pacific Gas and Electric Company (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 4.8 million customers and natural gas service to approximately 3.9 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 "Bankruptcy Court" in this report's discussion of the Utility's Chapter 11 filing). Pursuant to Chapter 11, the Utility retains control of its assets and is authorized to oper ate 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) and its subsidiaries, headquartered in Bethesda, Maryland. PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. PG&E NEG focuses on electricity generation and natural gas transmission in the United States of America. During February and March of 2003, certain lenders of PG&E Corporation exercised options to purchase 3 percent of the shares of PG&E NEG. No gain or loss was recognized by PG&E Corporation for this transaction. As discussed further in Note 3, 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, PG&E NEG a nd those 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. On July 8, 2003, PG&E NEG also filed a proposed plan of reorganization with the Bankruptcy Court that, if implemented, would eliminate PG&E Corporation's equity interest in PG&E NEG.

As a result of PG&E NEG's Chapter 11 filing and the resignation of PG&E Corporation's representatives who previously served on the PG&E NEG 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 PG&E NEG.

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, PG&E NEG, 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 Condensed 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 accounting principles generally accepted in the United States of America (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," and on a going-concern basis, which contemplates continuity of operation, realization of assets, and liquidation of liabilities in the ordinary course of business. PG&E NEG's Consolidated Financial Statements will be prepared in accordance with SOP 90-7 beginning in the third quarter of 2003. As a result of the Utility's and PG&E NEG's Chapter 11 filings, the realization of assets and liquidation of liabilities are subject to uncertainty. Under SOP 90-7, certain liabilities of the Utility existing prior to 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 rel ated 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.

Guarantor's Accounting and Disclosure Requirements for Guarantees

PG&E Corporation incorporated the disclosure requirements from Financial Accounting Standards Board (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 Statement of Financial Accounting Standards (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 this Statement 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 June 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 this Statement, 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 fossil facilities as a result of adopting this Statement was a loss of $1 million, after-tax.

If this Statement had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the three and six months ended June 30, 2002, would not have been material. The amounts recorded upon adoption of this Statement reflect the pro forma effects on the Consolidated Balance Sheets had this Statement 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 June 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 June 30, 2003, the Utility's estimated removal costs recorded in accumulated depreciation were approximately $1.7 billion.

• PG&E NEG has identified its generating facilities as having asset retirement obligations as of January 1, 2003. Upon implementation of SFAS No. 143, PG&E NEG recorded $2 million to its Property, Plant and Equipment to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, and recognized $3 million for asset retirement obligations. The cumulative effect of the change in accounting principle as a result of adopting this Statement was a loss of $3 million, after-tax, on PG&E Corporation Consolidated Statements of Operations. The impact to PG&E NEG of implementing SFAS No. 143 by its unconsolidated affiliates is immaterial.

If this Statement had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the three and six months ended June 30, 2002, would not have been material.

PG&E Gas Transmission, Northwest Corporation (PG&E GTN) may have potential asset retirement obligations under various land right documents associated with its gas transmission facilities. The majority of PG&E GTN's land rights are perpetual. Any non-perpetual land rights generally are renewed continuously because PG&E GTN 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.

PG&E GTN 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. PG&E GTN's estimated removal costs accrued in accumulated depreciation were approximately $11.7 million at June 30, 2003.

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). This Statement supersedes previous accounting guidance, principally Emerging Issues Task Force (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 this Statement did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility at the date of adoption.

Change from Gross to Net Method of Reporting Revenues and Expenses

Effective for the quarter ended September 30, 2002, PG&E Corporation changed its method of reporting gains and losses associated with energy trading contracts from the gross method of presentation to the net method. PG&E Corporation believes that the net method provides a more accurate and consistent presentation of energy trading activities on the financial statements. Amounts to be presented under the net method include all gross margin elements related to energy trading activities.

Previously, PG&E Corporation had reported unrealized gains and losses on trading activities on a net basis in operating revenues. However, PG&E Corporation had reported realized gains and losses on a gross basis in operating income, as both operating revenues and costs of commodity sales and fuel. PG&E Corporation now is reporting realized gains and losses from trading activities on a net basis as operating revenues.

Implementation of the net method has no net effect on gross margin, operating income, or net income. Prior year financial statements have been reclassified to conform to the net method. This change reduced generation, transportation and trading revenues, and cost of commodity sales and fuel by $2,441 million for the three months ended June 30, 2002, and $4,057 million for the six months ended June 30, 2002.

During the second quarter of 2003, PG&E NEG determined that its historical financial reporting presentation of revenues and expenses related to its hedging and certain Independent System Operator (ISO) sales and purchase 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, PG&E Corporation has adopted a net presentation approach for such transactions. PG&E Corporation believes that this method of presentation is preferable in the circumstances. Adopting this change reduced previously reported revenues and expenses by $50 million for the three months ended March 31, 2003, $262 million for the six months ended June 30, 2002, and $152 million for the three months ended June 30, 2002. In addition, the as revised amounts shown in t he table below, include adjustments principally for the effects of transactions between continuing and discontinued operations which, had not previously been eliminated from continuing operations. Such adjustments decreased previously reported revenues and expenses by $49 million for the three months ended March 31, 2003, and $87 million for the six months ended June 30, 2002, and increased revenues and expenses by $64 million for the three months ended June 30, 2002. The combined effects of the change in presentation and the adjustments described above on amounts included in previously issued statements of operations are summarized below.

		Three months ended March 31, 2003				Three months ended June 30, 2002				Six months ended June 30, 2002
		As Reported		As Revised(1)		As Reported (2)		As Revised		As Reported (2)		As Revised
Operating Revenues:
Energy Commodities     and Services		$	334	$	235	$	311	$	223	$	782	$	443
Total		2,401		2,302		3,025		2,937		5,949		5,610
Operating Expenses:
Energy Commidities    and Services		158		59		174		86		470		131
Total		$	2,530	$	2,431	$	2,242	$	2,154	$	3,864	$	3,525
(1)	Amounts shown above for the three months ended March 31, 2003, are not separately presented in the accompanying financial statements, but such amounts are reflected in the statement of operations for the six months ended June 30, 2003.
(2)	As Reported shown for the three and six months ended June 30, 2002, reflects the effects of netting trading revenues as described above and the exclusion of amounts related to discontinued operations described in Note 4.

The change did not result in a change in the consolidated operating income or net income, the Consolidated Balance Sheets or the Consolidated Statements of Cash Flows.

Rescission of EITF 98-10

In October 2002, the EITF rescinded EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). Energy trading contracts that are derivatives in accordance with SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" (collectively, SFAS No. 133), will 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 now are accounted for at cost, through a one-time adjustment recorded as a cumulative effect of a change in accounting principle. This requirement was effective as of January 1, 2003, and resulted in a $3 million loss, net of zero tax benefits as a cumulative effect of accounting change. For PG&E Corporation, the majority of trading contracts are derivative instrum ents 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.

Earnings Per Share

Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is computed by dividing net income (loss), 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 (loss) and weighted average common shares outstanding for calculating basic and diluted net income (loss) per share:

				Three months ended				Six months ended
				June 30,				June 30,
(in millions, except per share amounts)				2003		2002		2003		2002
Income (Loss) from continuing operations				$	219	$	279	$	(59)	$	903
Discontinued operations					8		-		(62)		7
Net income (loss) before cumulative effect of changes
	in accounting principles			227		279		(121)		910
Cumulative effect of changes in accounting principles				-		(61)		(6)		(61)
Net Income (Loss)				227		218		(127)		849
Interest expense on 9.5% Convertible Subordinated Notes (1)				4		-		-		-
Net Income (Loss) for Diluted Calculations				$	231	$	218	$	(127)	$	849
Weighted average common shares outstanding, basic				384		366		383		365
Add:			Employee stock options and PG&E Corporation
			shares held by grantor trusts	2		5		-		5
			PG&E Corporation Warrants (2)	5		-		-		-
			9.5% Convertible Subordinated Notes	18		1		-		-
Shares outstanding for diluted calculations				409		372		383		370
Earnings (Loss) Per Common Share, Basic
Income (loss) from continuing operations				$	0.57	$	0.76	$	(0.15)	$	2.48
Discontinued operations				0.02		-		(0.16)		0.02
Cumulative effect of changes in accounting principles				-		(0.16)		(0.02)		(0.17)
Net earnings (loss)				$	0.59	$	0.60	$	(0.33)	$	2.33
Earnings (Loss) Per Common Share, Diluted
Income (loss) from continuing operations				$	0.54	$	0.75	$	(0.15)	$	2.44
Discontinued operations				0.02		-		(0.16)		0.02
Cumulative effect of changes in accounting principles				-		(0.16)		(0.02)		(0.17)
Net earnings (loss)				$	0.56	$	0.59	$	(0.33)	$	2.29
(1)		Interest expense, including amortization of the discount, on the 9.5 percent Convertible Subordinated Notes for the three and six months ended June 30, 2002, was $232,276, net of income tax of $159,724.
(2)		The incremental shares associated with PG&E Corporation Warrants were 157,995 shares for the three months ended June 30, 2002, and 79,433 shares for the six months ended June 30, 2002.

The diluted earnings per share for the six months ended June 30, 2003, excludes approximately 1 million incremental shares related to employee stock options and shares held by grantor trusts, 5 million incremental shares related to warrants, and 18 million incremental shares related to the 9.5 percent Convertible Subordinated Notes, and includes associated interest expense of $8 million (net of income taxes of $6 million) due to the anti-dilutive effect upon loss from continuing operations.

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." 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 (loss) and earnings (loss) per share would have been as follows:

			Three months ended				Six months ended
			June 30,				June 30,
(in millions, except per share amounts)			2003		2002		2003		2002
Net income (loss):
As reported			$	227	$	218	$	(127)	$	849
	Deduct: Total stock-based employee
		compensation expense determined
		under the fair value based method
		for all awards, net of related tax effects		5		5		10		10
Pro forma			$	222	$	213	$	(137)	$	839
Basic earnings (loss) per share:
As reported				0.59		0.60		(0.33)		2.33
Pro forma				0.58		0.58		(0.36)		2.30
Diluted earnings (loss) per share:
As reported				0.56		0.59		(0.33)		2.29
Pro forma				0.55		0.57		(0.36)		2.27

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				Six months ended
			June 30,				June 30,
(in millions)			2003		2002		2003		2002
Income available for common stock:
As reported			$	339	$	463	$	260	$	1,053
	Deduct: Total stock-based employee
		compensation expense determined
		under the fair value based method
		for all awards, net of related tax effects		2		2		4		4
Pro forma			$	337	$	461	$	256	$	1,049

As of June 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. Restrictions to 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.

Total compensation expense resulting from the restricted stock issuance reflected on PG&E Corporation's Consolidated Statements of Operations was $1.8 million for the three-month and $3.2 million for the six-month periods ended June 30, 2003, of which $1.0 million for the three-month and $1.9 million for the six-month periods was recognized by the Utility.

Comprehensive Income (Loss)

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

	PG&E Corporation				Utility
(in millions)	2003		2002		2003		2002
Three months ended June 30
Net income available for (loss allocated to)   common stock	$	227	$	218	$	339	$	463
Net loss in other comprehensive income (OCI)   from current period hedging transactions and price   changes in accordance with SFAS No. 133	(4)		(9)		-		-
Net reclassification from OCI to earnings	10		-		-		-
Foreign currency translation adjustment	-		3		-		2
Retirement plan remeasurement (Note 8)		(60)		-		(60)		-
Other		-		1		-		-
Comprehensive income (loss)	$	173	$	213	$	279	$	465
Six months ended June 30
Net income (loss) available for (loss allocated to)   common stock	$	(127)	$	849	$	260	$	1,053
Net loss in OCI from current period hedging   transactions and price changes in accordance with   SFAS No. 133	(5)		(84)		-		-
Net reclassification from OCI to earnings	15		5		-		-
Foreign currency translation adjustment	3		3		-		2
Retirement plan remeasurement (Note 8)		(60)		-		(60)		-
Other		-		1		-		-
Comprehensive income (loss)	$	(174)	$	774	$	200	$	1,055

The above changes to OCI are stated net of income taxes (benefits)of $(37) million and $(46) million for the three- and six-month periods ended June 30, 2003, and $(14) million and $24 million for the three- and six-month periods ended June 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 PG&E NEG. Valuation allowances of $7 million for the three-month and $17 million for the six-month periods ended June 30, 2003, were recorded in continuing operations. Additional valuation allowances of $7 million were recorded in discontinued operations, and $5 million in accumulated other comprehensive loss for the six-month period ended June 30, 2003.

In addition to the above reserves, PG&E NEG recorded valuation allowances due to the uncertainty of realizing federal deferred tax assets. These valuation allowances were determined on a stand-alone basis. Valuation allowances of $56 million for the three-month and $122 million for six-month periods ended June 30, 2003, were recorded in continuing operations. Additional valuation allowances (benefits) of $(2) million and $35 million were recorded in discontinued operations, zero and $3 million recorded in cumulative effect of changes in accounting principles, and $(4) million and $44 million recorded in accumulated other comprehensive loss for the three and six months ended June 30, 2003. These PG&E NEG valuation allowances are eliminated in consolidation.

Related Party 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 provided. 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 transmission services from PG&E GTN. Effective April 1, 2003, the Utility no longer purchases gas commodity from PG&E Energy Trading (PG&E ET). The Utility continues to sell reservation and othe r ancillary services to PG&E 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 June 30,				Six Months Ended June 30,				Receivable (Payable) Balance Outstanding at
									June 30,		December 31,
(in millions)	2003		2002		2003		2002		2003		2002
Utility revenues from:
Administrative services provided to    PG&E Corporation	$	2	$	2	$	4	$	3	$	2	$	1
Gas reservation services provided to    PG&E ET	1		3		4		6		-		-
Contribution in aid of construction received    from PG&E NEG	-		-		-		-		-		3
Trade deposit due from PG&E GTN	-		-		3		-		15		12
Utility expenses from:
Administrative services received from    PG&E Corporation	$	85	$	23	$	98	$	50	$	(358)	$	(289)
Interest accrued on pre-petition liability due to    PG&E Corporation	2		-		4		-		(2)		(2)
Administrative services received    from PG&E NEG	1		-		2		-		(1)		(2)
Software purchases from PG&E ET	1		-		1		-		-		-
Gas commodity services    received from PG&E ET	-		9		10		28		(1)		(26)
Gas transmission services received    from PG&E GTN	14		10		29		22		(8)		(8)
Trade deposit due to PG&E ET	-		-		1		-		(5)		(7)

Payment of outstanding amounts owed as of July 8, 2003, the date of PG&E NEG's Chapter 11 filing, are subject to the approval of the Bankruptcy Court.

Accounting Pronouncements Issued But Not Yet Adopted

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 qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. Certain derivative contracts 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. 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.

The assessment of whether the contract qualifies for the normal purchase and sales exception, including whether the price adjustment is clearly and closely related to the asset being transacted, must be performed at the inception of the contract.

The implementation guidance in DIG C20 is effective for all existing and all future derivative contracts in the quarter beginning after July 10, 2003 (fourth quarter of 2003). Early application in the third quarter of 2003 is permitted. 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.

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

In May 2003, the FASB issued Statement No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). The Statement addresses concerns of how to measure and classify in the statement of financial position 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.

The requirements of SFAS No. 150 are applicable to PG&E Corporation in the third quarter of 2003. The Statement will be implemented by reclassifying and remeasuring the Utility's $137 million of preferred stock with mandatory redemption provisions as a liability, at the present value of the redemption amount using the rate implicit in the contract at inception, without reclassifying prior dividends or accruals. The remeasurement and reclassification will not have an impact on earnings of PG&E Corporation or the Utility. The preferred stock with mandatory redemption provisions are to be measured subsequently at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at the reporting date. All amounts paid or to be paid to the holders of the financial instruments in excess of the initial measured amount are reflected in interest cost.

Determining Whether an Arrangement Contains a Lease

In May 2003, the 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. PG&E Corporation and the Utility currently are assessing the impact of EITF 01-8.

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 under what circumstances 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. PG&E Corporation and the Utility are currently evaluating the impacts, if any, of SFAS No. 149 on its Consolidated Financial Statements.

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 or arrangement with which it is involved. A "variable interest entity" is an entity that does not have sufficient equity investment at risk to permit the entity to finance its activities without additional subordinated financial support from other parties or an entity where equity investors lack 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 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 between February 1, 2003, and June 30, 2003. The consolidation requirements are applicable to PG&E Corporation in the third quarter of 2003. PG&E Corporation and the Utility are evaluating the impacts of FIN 46's initial recognition, measurement, and disclosure provisions on the Consolidated Financial Statements, and currently are unable to estimate variable interest entities that will be consolidated or disclosed when FIN 46 becomes effective.

NOTE 2: THE 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 holds 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 $50.1 billion. Of these claims, approximately $27.0 billion have 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 $5.0 billion of the remaining $23.1 billion of filed claims. These objections relate primarily to the ISO, California Power Exchange (PX), and generator claims. Generator claims could be reduced significantly based on the FERC's March 26, 2003, decision finding that electricity suppliers overcharged California buyers, including California investor-owned utilities (IOUs), from October 2, 2000, to June 20, 2001. In addition, the Utility is in settlement discussions with certain claimants. These settlement discussions could further reduce outstanding claims. Finally, of the remaining $23.1 billion of filed claims, approximately $5.4 billion are expected to pass through the Chapter 11 proceeding and be determined in the appropriate court or other tribunal during or after the Chapter 11 proceeding.

The Utility has recorded its estimate of all valid claims at June 30, 2003, as $9.5 billion of Liabilities Subject to Compromise and $3.0 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 six months ended June 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 vendors.

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 June 30, 2003 (per annum)
Commercial Paper Claims	$	873	7.841%
Floating Rate Notes	1,240		7.958%
Senior Notes	680		10.000%
Medium-Term Notes	287		6.185% to 8.825%
Revolving Line of Credit Claims	938		8.375%
QFs	56		5.000%
Other Claims	5,382		Various
Liabilities Subject to Compromise at June 30, 2003	$	9,456

As the Utility's proposed plan of reorganization (see below) did not become effective on or before February 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 37.5 basis points over the originally agreed upon rates, for periods on and after February 15, 2003. Since the plan of reorganization will not become effective on or before September 15, 2003, the interest rates for these claims on and after such date will be increased by an additional 37.5 basis points. Finally, if the effective date does not occur on or before March 15, 2004, the interest rates for these claims on and after such date will be increased 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 a competing 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.

The Proposed 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 settlement agreement, PG&E Corporation and the Utility would agree that they no longer would propose to disaggregate the historic businesses of the Utility as had been proposed in their original plan of reorganization. Instead, the Utility would remain a vertically integrated utility subject to the CPUC's jurisdiction.

The treatment of creditors under the Settlement Plan would be consistent with that provided in the Utility's original plan of reorganization, except that those creditors that were to receive long-term notes to be issued by the limited liability companies contemplated under the original plan of reorganization or a combination of cash and long-term notes would be paid entirely in cash. The Settlement Plan contemplates satisfaction of allowed claims in the Utility's Chapter 11 proceeding in cash from the issuance of approximately $8.7 billion in debt (which may be either secured or unsecured depending on market conditions at the time of issuance), cash on hand, or, in some cases, the reinstatement of the underlying debt. 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 re instated debt will be reinstated.

The proposed 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 settlement agreement must be executed by all parties on or before December 31, 2003. The CPUC will conduct evidentiary hearings during September 2003 before deciding whether or not to approve the proposed settlement agreement. On July 25, 2003, the Utility filed its testimony in support of the proposed settlement agreement. Testimony from the staff of the CPUC and the OCC was also filed on July 25, 2003. The CPUC currently is expected to vote on the settlement agreement on December 18, 2003.

In addition, the Bankruptcy Court must confirm the Settlement Plan. While the CPUC is not a proponent, it would agree under the proposed settlement agreement to support the Settlement Plan. On July 31, 2003, the Bankruptcy Court approved the disclosure statement that will be used to solicit approval of the Settlement Plan from creditors entitled to vote on the Settlement Plan. On August 1, 2003, the Bankruptcy Court approved the solicitation procedures and ordered that the solicitation period to start on August 15 and end on September 29, 2003. The Bankruptcy Court has ordered that the confirmation hearing begin on November 3, 2003, and that all objections to the Settlement Plan be filed by September 2, 2003.

Regulatory Assets

The proposed settlement agreement provides for a new regulatory asset (Regulatory Asset) to restore the Utility to financial health and to maintain and improve the Utility's financial health in the future. The Regulatory Asset would be a separate and additional part of the Utility's rate base of approximately $3.7 billion, pre-tax, included in non-current assets on the Utility's balance sheet. The Regulatory Asset would be amortized on a mortgage-style basis over nine years beginning January 1, 2004.

The Utility would continue to cooperate with the CPUC and the State of California in seeking refunds from power generators. The net after-tax amount of any refunds, claim offsets, or other credits from generators or other energy suppliers relating to the Utility's power procurement costs that the Utility actually realizes in cash or by offset of creditor claims in its Chapter 11 proceeding would be applied to reduce the outstanding balance and the remaining amortization of the Regulatory Asset. Amounts received in cash by the Utility for electric claims under the master settlement agreement with El Paso Corporation and certain of its affiliates (El Paso) also would be included in such a reduction.

The Regulatory Asset would earn a return on equity (ROE) of at least 11.22 percent for the life of the Regulatory Asset. For 2004 and 2005, the common equity ratio of the Utility's capital structure would be the higher of forecast average equity ratio (in accordance with the 2003 cost of capital proceeding to be filed by the Utility for calendar year 2004 and the 2005 cost of capital proceeding, or such other CPUC proceedings as may be appropriate) or 48.60 percent. Once the common equity ratio of the Utility's capital structure reaches 52.00 percent, the authorized common equity ratio of the Regulatory Asset would be no less than 52.00 percent for the remaining life of the Regulatory Asset. The CPUC would use its usual method for tax-effecting the ROE component of the Regulatory Asset in establishing the Utility's revenue requirements for the Regulatory Asset. The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

The CPUC would agree that the Utility's rate base for the 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 regulatory asset of approximately $1.3 billion, pre-tax, for the future recovery of generation-related assets that were charged to expense in 2000. The CPUC would not be precluded from determining the reasonableness of any capital expenditures made for URG after the effective date of the Settlement Plan. The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

The CPUC would not reduce or impair the value of the Regulatory Asset or the Utility's rate base for its URG, by taking the Regulatory Asset or the Utility's rate base for its URG, or their amortization or earnings into account when setting other Utility revenue requirements and resulting rates. The CPUC also would not take the settlement agreement or the Regulatory Asset into account in establishing the Utility's authorized ROE or capital structure.

Among other terms, the proposed settlement agreement also provides that:

Ratemaking Matters

• The CPUC would maintain the Utility's retail electric rates at current levels through December 31, 2003. Beginning January 1, 2004, the CPUC may adjust the Utility's retail electric rates prospectively consistent with the proposed settlement agreement, the Settlement Plan, the order confirming the Settlement Plan, and California law. The proposed settlement agreement contemplates that retail electric 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 and provided that from January 1, 2004, until Standard & Poor's (S&P) has issued a long-term issuer credit rating for the Utility of at least A- or Moody's Investors Services (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 forecast average equity ratio in the Utility's cost of capital proceeding or 48.60 percent.

• Balances in the Utility's Transition Cost Balancing Account (which tracks the amount of the Utility's under-collected transition and electricity procurement costs) as of the effective date of the Settlement Plan would have no further impact on the Utility's retail electric rates and would not be subject to further CPUC review except for verification of recorded balances.

• 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 California legislation (Assembly Bill (AB) 57 and Senate Bill (SB) 1976) and the CPUC-California Department of Water Resources (DWR) rate agreement 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 URG, 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 previously incurred costs of providing electric service from ratepayers under the federal filed rate doctrine, the settlement agreement, the Regulatory Asset, or any other matters addressed or resolved by the proposed settlement agreement.

• The Utility would file an advice letter to implement all of the rate and tariff changes necessary to implement the Settlement Plan. The CPUC would act promptly on the advice filing and revised rates and tariffs. The CPUC also would 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 Sheet.

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 (1) the Utility receives a long-term issuer credit rating of at least A from S&P and A2 from Moody's, after giving effect to such assignment or assumption, (2) the CPUC first has made a finding that the DWR contracts being assumed are just and reasonable, and (3) the CPUC has acted to ensure that the Utility receives full and timely rate recovery of all costs of the DWR contracts over their lives without further review. The CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law.

Headroom Revenues - 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 settlement defines headroom as the Utility's total net after-tax income reported under 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 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 settlement agreement provides that if headroom revenues accrued by the Utility during 2003 are greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom revenues are less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in rates. Headroom revenues for the six months ended June 30, 2003, were $237 million, pre-tax, as calculated under the terms of the proposed settlement agreement.

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 no longer is subject to appeal, the Utility would dismiss with prejudice its "filed rate case" and withdraw the original plan of reorganization. In addition, the CPUC would 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.

Fees and Expenses - The proposed settlement agreement would require the Utility to reimburse PG&E Corporation and the CPUC after the date the Settlement Plan is confirmed for all of their respective professional fees and expenses incurred in connection with the Chapter 11 proceeding. Of such amounts, the amounts reimbursed to the CPUC could be recovered from ratepayers. As of June 30, 2003, PG&E Corporation has incurred expenses of approximately $121 million on the Utility's Chapter 11 proceeding.

Environmental Measures - The Utility would implement three environmental enhancement measures:

• The Utility would encumber with conservation easements or donate approximately 140,000 acres of specific watershed and other 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 such corporation over ten years with $70 million, although it would be entitled to recover these payments in rates without further review; and

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

Term - The proposed settlement agreement generally would terminate nine years after the effective date of the Settlement Plan, except that all vested rights of the parties under the proposed settlement agreement would survive termination for the purpose of enforcement.

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 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 deemed 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 notes 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 notes to be offered by the Utility of not less than BBB- and Baa3, respectively;

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

• Each of the parties to the proposed settlement agreement have 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 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 settlement agreement and related rates, or if the CPUC takes actions materially inconsistent with the proposed 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 below, then the Utility's financial condition and results of operations could be materially adversely affected. The settlement agreement and Settlement Plan may also be affected by the outcome of the California Supreme Court's consideration of questions certified to it by the Ninth Circuit regarding the validity of a settlement agreement between the CPUC and another California IOU, Southern California Edison Com pany (SCE). Several entities, including The Utility Reform Network (TURN) challenged the SCE settlement. Oral argument occurred before the California Supreme Court on May 27, 2003, and it is expected that the Court will issue a ruling by August 27, 2003. The Utility believes that, even if the California Supreme Court finds the SCE settlement violates state law, there are independent legal and factual reasons under which the proposed settlement agreement and the Settlement Plan would still be valid under state and federal law. The effectiveness of the Settlement Plan is not conditioned upon receiving a favorable ruling in the SCE case by the California Supreme Court.

NOTE 3: PG&E NEG CHAPTER 11 FILING

Chapter 11 Filing

On July 8, 2003, PG&E NEG filed voluntary petitions for relief under the provisions of Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. In addition, on July 8, 2003, each of the following indirect wholly owned subsidiaries of PG&E NEG filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code in the Bankruptcy Court: PG&E ET Investments Corporation; PG&E Energy Trading Holdings Corporation; PG&E Energy Trading-Power, L.P.; and PG&E Energy Trading - Gas Corporation; (collectively, the "ET Companies"); and, separately, USGen New England, Inc. (USGenNE). On July 29, 2003, two other subsidiaries, Quantum Ventures and 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 PG&E NEG and other subsidiaries.

Pursuant to Chapter 11 of the Bankruptcy Code, PG&E NEG, and these 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. Additionally, on July 8, 2003, PG&E NEG 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 facilities, acting in their individual capacities. PG&E NEG's proposed plan of reorganization would not restructure the indebtedness of any of the debtors, other than PG&E NEG. If PG&E NEG's plan of reorganization is confirmed by the Bankruptcy Court and implemented, PG&E Corporation no longer would have any equity interest in PG&E NEG 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 of June 30, 2003, PG&E NEG had consolidated assets of $6.8 billion and liabilities of $8.3 billion. As of June 30, 2003, PG&E Corporation's net investment in PG&E NEG was a negative $1.1 billion, including approximately $400 million of intercompany receivables.

The accompanying PG&E Corporation Consolidated Financial Statements include the consolidated results of PG&E NEG through June 30, 2003. As a result of PG&E NEG's Chapter 11 filing and the resignation of PG&E Corporation's representatives who previously served on the PG&E NEG 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 PG&E NEG. Accordingly, effective July 8, 2003, PG&E Corporation no longer will consolidate PG&E NEG's financial results and will begin accounting for its investment in PG&E NEG using the cost method. In accordance with the cost method, PG&E Corporation no longer will recognize its equity share in the income or losses of PG&E NEG and will record its investment in and advances to PG&E NEG as a non-current liability on the Consolidated Balance Sheets. This investment will not be affected by changes in PG&E NEG's future financial results, other than (1) investments in or dividends from PG&E NEG, or (2) income taxes PG&E Corporation may be required to pay if the Interal Revenue Service disallows certain deductions or tax credits attributable to PG&E NEG and its subsidiaries for the past tax years that were incorporated into PG&E Corporation's consolidated tax returns.

If PG&E NEG's plan of reorganization is implemented and PG&E Corporation's equity in PG&E NEG is eliminated, PG&E Corporation will bring its net investment in PG&E NEG to zero and, as a result, recognize a one-time non-cash gain to earnings. The amount of such potential gain cannot be estimated at this time.

Debt in Default and Long-Term Debt

PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $5.6 billion, of which approximately $2.8 billion is debt that is non-recourse to PG&E NEG. PG&E NEG currently does not have sufficient cash to meet its financial obligations and has ceased making payments on its debt and equity commitments.

The schedule below summarizes PG&E NEG's and its subsidiaries outstanding debt in default and long-term debt at June 30, 2003, and December 31, 2002:

(in millions)			Outstanding Balance At
Description	Maturity	Interest Rates	June 30, 2003		December 31, 2002
Debt in default:
PG&E NEG, Inc. Senior Unsecured Notes	2011	10.375%	$	1,000	$		1,000
PG&E NEG, Inc. Credit Facility-Tranche B   (364-day)	11/14/02	Prime plus credit spread	431		431
PG&E NEG, Inc. Credit Facility-Tranche A   (2-year facility with a $195 million   maximum commitment)	8/23/03	Prime plus credit spread	80		42
Turbine and Equipment Facility	12/31/03	Prime plus credit spread	205		205
USGenNE Credit Facility	9/1/03	LIBOR plus credit spread	75		-
GenHoldings Construction Facility Tranche A	12/5/03	LIBOR plus credit spread	290		118
GenHoldings Construction Facility Tranche B	12/5/03	LIBOR plus credit spread	1,068		1,068
GenHoldings Swap Termination	-	-	50		50
Lake Road Construction Facility Tranche A	12/11/02	Prime plus credit spread	227		227
Lake Road Construction Facility Tranche B	12/11/02	Prime plus credit spread	219		219
Lake Road Working Capital Facility	12/9/03	Prime plus credit spread	9		23
Lake Road Swap Termination	12/11/02	-	62		61
La Paloma Construction Facility Tranche A	12/11/02	Prime plus credit spread	383		367
La Paloma Construction Facility Tranche B	12/11/02	Prime plus credit spread	304		291
La Paloma Construction Facility Tranche C	12/11/02	Prime plus credit spread	21		20
La Paloma Working Capital Facility	12/9/03	Prime plus credit spread	22		29
La Paloma Swap Termination	12/11/02	-	83		79
Other debt related to Attala	Various	LIBOR plus credit spread	237		-
Subtotal				4,766			4,230
Long-term debt:
PG&E GTN Senior Unsecured Notes	2005	7.10%		250			250
PG&E GTN Senior Unsecured Debentures	2025	7.80%	150		150
PG&E GTN Senior Unsecured Notes	2012	6.62%	100		100
PG&E GTN Medium-Term Note	2003	6.96%	6		6
PG&E GTN Credit Facility	5/2/05	LIBOR plus credit spread	27		58
USGenNE Credit Facility	9/1/03	LIBOR plus credit spread	-		75
Plains End Construction Facility	9/6/06	LIBOR plus credit spread	65		56
Mortgage loan payable	2010	CP rate plus 6.07%	7		7
Other	Various	Various	17		20
Subtotal				622		722
Total Debt in default and Long-term debt			$	5,388	$	4,952

	Outstanding Balance At
Description	June 30, 2003		December 31, 2002
Amounts classified as Debt in default	$	4,691	$	4,230
Amount related to liabilities held for sale, classified as current		75			75
Long-term debt, classified as current		11	17
Long-term debt		611	630
Total Debt in default and Long-term debt	$	5,388	$		4,952

Accrued Interest - As of June 30, 2003, accrued interest was recorded on the following debt instruments:

(in millions)
PG&E NEG Senior Unsecured Notes	$	117
PG&E NEG Inc. Credit Facility	28
GenHoldings Facility	13
Turbine and Equipment Facility	12
Lake Road Facilities	26
La Paloma Facilities	5
PG&E GTN Facilities	5
Other		12
Total	$	218

GenHoldings Construction Facility - In December 2001, PG&E NEG entered into a $1.075 billion five-year non-recourse credit facility for a portfolio of generating projects held by GenHoldings I, LLC (GenHoldings), an indirect subsidiary of PG&E NEG. The credit facility, which was increased to $1.460 billion on April 5, 2002, is secured by the Millennium, Harquahala Generating Company, LLC (Harquahala), Covert Generating Company, LLC (Covert), and Athens Generating Company, LLC (Athens) generating projects. The facility was used to reimburse PG&E NEG and lenders for a portion of the construction costs already incurred on these projects and to fund a portion of the balance of the construction costs through completion.

GenHoldings defaulted under its credit agreement by failing to make equity contributions to fund a portion of the construction draws for the Athens, Harquahala, and Covert projects. In November and December 2002, GenHoldings' lenders executed waivers and amendments to the credit agreement under which they agreed to continue to waive GenHoldings' equity default until June 30, 2003, and increased loan commitments to cover such shortfall.

In connection with the lenders' waiver of various defaults and additional funding commitments, PG&E NEG agreed to cooperate with any reasonable proposal by the lenders regarding disposition of the equity in or assets of all of the PG&E NEG subsidiaries holding the Athens, Covert, Harquahala, and Millennium projects. An event of default would occur if these projects are not transferred to the lenders or their designees by August 29, 2003, which would trigger lender remedies including the right to foreclose on the projects. The administrative agent has the discretion to extend this date to September 30, 2003.

PG&E NEG has reaffirmed its guarantee of GenHoldings' remaining obligation to make equity contributions to these projects of approximately $355 million. This guarantee will remain an obligation of PG&E NEG after the transfer of the projects.

Lake Road and La Paloma Construction Facilities - In September 1999 and March 2000, Lake Road Generating Company, LP (Lake Road) and La Paloma Generating Company, LLC (La Paloma) entered into participation agreements to finance the construction of the two plants. In November 2002, Lake Road and La Paloma defaulted on their obligations to pay interest and swap payments. In addition, as a result of PG&E NEG's downgrade to below investment grade by both S&P and Moody's, PG&E NEG, as guarantor of certain debt obligations of Lake Road and La Paloma, became required to make equity contributions to Lake Road of $230 million and $375 million to La Paloma.

As of December 4, 2002, Lake Road and La Paloma entered into various agreements with their respective lenders providing for (1) funding of construction costs required to complete the La Paloma facility, and (2) additional working capital facilities to enable each subsidiary to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission system operator requirements, as well as for general working capital purposes. Lenders extending new credit under these agreements have received liens on the projects that are senior to the existing lenders' liens. These agreements require, among other things, the transfer of the Lake Road and La Paloma projects and all associated contracts and agreements to the respective lenders by June 9, 2003. On June 8, 2003, an amendment extended this date to September 30, 2003.

Impairments, Write-offs, and Other Charges

Consolidation and Impairment of Attala Generating Company LLC

On May 7, 2002, Attala Generating Company LLC (Attala Generating), an indirect wholly owned subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back a 526-megawatt (MW) generation facility (Attala Facility) in Mississippi to two third-party special-purpose entities (SPEs). These entities funded the acquisition of their undivided interests in the Attala Facility through proceeds from the issuance of debt and equity. The SPEs funded $103 million, or approximately 30 percent of the total fair value of the Attala Facility on the transaction date, from the issuance of equity. The related transaction was accounted for as a lease because the owners of the SPEs had made an initial substantive residual equity capital investment that was intended to be at risk during the entire term of the lease.

During January 2003, the SPEs distributed cash to their equity holders, which resulted in the SPEs no longer meeting the substantive equity at risk criteria, under current accounting requirements. PG&E NEG now consolidates the assets and liabilities of the SPEs.

The consolidation of the SPEs resulted in an increase in assets of $62 million, representing the estimated fair value of the Attala Facility and related inventories, and debt of $237 million, representing the bonds issued to finance the sale-leaseback transaction. As the liabilities of the SPEs exceed their assets, a pre-tax charge to earnings of $175 million was recorded in the first quarter of 2003.

In January 2003, the FASB issued FIN 46. See Note 1, "General - Adoption of New Accounting Policies," for a more complete description of FIN 46. PG&E NEG currently is evaluating the impacts of FIN 46's initial recognition, measurement, and disclosure provisions on its Consolidated Financial Statements when these requirements become effective by the beginning of the third quarter of 2003.

PG&E Corporation believes that, upon the adoption of FIN 46, PG&E NEG will not be required to continue to consolidate the SPEs associated with the sale-leaseback of the Attala Facility, since it has neither an equity investment nor a significant variable interest in the SPEs. Depending on the method of adopting FIN 46 by PG&E NEG, either the difference between the book values of the SPEs' assets and liabilities will be recognized through earnings, or first quarter 2003 financial statements will be restated to eliminate the impact of initially consolidating the SPEs. Future earnings also may be impacted by the accrual of any probable payments under the Attala guarantee arrangement disclosed in Note 6.

Shaw Settlement Charges

In connection with the terms of a proposed settlement of all pending disputes among Shaw Group Inc. (Shaw), Harquahala, Covert, and PG&E NEG, PG&E NEG recognized a pre-tax charge of approximately $32 million for anticipated legal settlement costs in the first quarter ended March 31, 2003. Harquahala and Covert are indirect subsidiaries of PG&E NEG.

The Harquahala generating facility, owned by Harquahala, is a 1,092 MW plant located in Tonopah, Arizona, with about 88 percent of the construction complete. Covert generating facility, owned by Covert, is a 1,170 MW plant located in Covert, Michigan, with about 84 percent of construction complete. The equity in Covert and Harquahala is owned by GenHoldings. On August 13, 2001, Harquahala and Covert entered into engineering procurement and construction contracts (EPCs) with Shaw to design, procure materials and equipment for, and construct these generating facilities.

During November and December 2002, Harquahala commenced arbitration against Shaw seeking a declaration that it was not obligated to withhold payments from a certain third party connected with the construction of the facility. Subsequently, Shaw commenced arbitration against Covert and Harquahala to recover the fees and expenses associated with certain change order requests. In addition, Shaw filed a lawsuit against Harquahala, Covert, PG&E NEG, and NEG Construction Finance Company, LLC (CFC), alleging that it had not received adequate assurance of payment from PG&E NEG.

Under the terms of a definitive settlement agreement, effective May 16, 2003, PG&E NEG paid approximately $32.5 million to Shaw, and the EPC contracts were increased in the aggregate by $65 million (the balance funded by the lenders). In addition, the completion deadlines were extended, the cost-sharing agreements and related guarantees were terminated, and PG&E NEG's completion guarantees to the lenders were released. The remaining $32.5 million is an obligation of Covert and Harquahala under their construction financing arrangements.

Mantua Creek Project

The Mantua Creek project is a 897 MW combined cycle merchant power plant located in the Township of West Depford, New Jersey. Due to liquidity constraints, PG&E NEG no longer could provide equity contributions to the project and beginning in the fourth quarter of 2002, began to suspend or terminate contracts with vendors. At December 31, 2002, PG&E NEG wrote off capitalized development and construction costs of $257 million and established an additional accrual of $22 million for charges and associated termination costs. In the six months ended June 30, 2003, various termination cost accruals were adjusted as settlements occurred resulting in an approximate $8 million reduction in impairment expense.

DTE-Georgetown

On June 26, 2003, PG&E GTN, PG&E ET, and DTE Georgetown, LLC (DTE) entered into a termination agreement that terminated a tolling agreement between DTE and PG&E ET dated May 23, 2000. In consideration for a payment of approximately $30 million by PG&E ET, the termination agreement releases and discharges PG&E ET from any and all obligations under the tolling agreement and PG&E GTN from any and all obligations under its guarantee of PG&E ET's obligations, subject to restoration of PG&E GTN's guarantee obligation in the limited event that DTE may be required to disgorge amounts received from PG&E ET. Under the tolling agreement, PG&E ET would have had to make capacity payments totaling approximately $64 million over the next seven years. PG&E NEG recorded this $30 million payment as a charge to impairment expense in the three months ended June 30, 2003.

NOTE 4: DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

USGen New England - In September 1998, USGenNE acquired the non-nuclear generating assets of the New England Electric System (NEES) for approximately $1.8 billion. These assets included:

• 2,344 MW of coal- and oil-fired power plants in Massachusetts;

• 1,166 MW of hydroelectric facilities in New Hampshire, Vermont, and Massachusetts;

• 495 MW of gas-fired power plants in Rhode Island;

• Above-market power purchase agreements with support payments provided by NEES for the first nine years;

• Gas pipeline transportation contracts; and

• Transition wholesale load contracts known as Standard Offer Agreements.

Consistent with its previously announced strategy of disposing of certain merchant assets, in December 2002, the Board of Directors of PG&E Corporation approved management's plans for the proposed sale of USGenNE. Under the provisions of SFAS No. 144, the equity of USGenNE is accounted for as an asset held for sale. This requires that the asset be recorded at the lower of fair value, less costs to sell, or book value. Based on the then current estimated fair value (based on the estimated proceeds) of a sale of USGenNE, PG&E NEG recorded a pre-tax loss of $1.1 billion in the fourth quarter of 2002. It is anticipated that arrangements for the disposition of the USGenNE assets will be made during 2003. However, as a result of required regulatory approval by the FERC, it is anticipated that any disposals will not be consummated until 2004. The operating results from USGenNE are being reported as discontinued operations in the Consolidated Financial Statements of PG&E NEG and PG& E Corporation. Also, under the provisions of SFAS No. 144, no depreciation has been recorded on these assets held for sale.

Mountain View - In December 2002, the Board of Directors of PG&E Corporation approved the sale of Mountain View Power Partners, LLC and Mountain View Power Partners II, LLC, which had been merged on October 1, 2002 (collectively referred to as Mountain View). On December 18, 2002, a subsidiary of PG&E NEG entered into an agreement to sell Mountain View to Centennial Power, Inc. The sale occurred on January 3, 2003. PG&E NEG received $102 million in proceeds for the sale of Mountain View, resulting in a $19 million pre-tax gain.

Under the provisions of SFAS No. 144, Mountain View is accounted for as an asset held for sale. The operating results and gains on sale of Mountain View are reported as discontinued operations in the Consolidated Financial Statements of PG&E NEG and PG&E Corporation.

ET Canada - On March 18, 2003, PG&E Energy Trading-Gas Corporation (ET-Gas), a subsidiary of PG&E NEG, completed the sale of 100 percent of the stock of PG&E Energy Trading, Canada Corporation (ET Canada) to Seminole Canada Gas Company, a Nova Scotia unlimited liability company (Seminole). Seminole transferred approximately $86 million at closing to ET-Gas and several of its affiliates, representing the purchase price and the return of collateral posted by ET-Gas and ET Canada to support ET Canada's energy trading transactions, plus interest. Most of the proceeds were used to repay principal and interest on an outstanding loan of $76 million to another affiliate.

Seminole also replaced certain letters of credit issued to support ET Canada's energy trading transactions and obtained the release of ET-Gas and its affiliates, including PG&E GTN and PG&E NEG, from obligations under guarantees supporting the letters of credit. Seminole has indemnified ET-Gas for any liability under the letters of credit or the guarantees. As previously disclosed, in the fourth quarter of 2002, PG&E NEG and PG&E Corporation recorded a $25 million pre-tax loss on the anticipated disposition of ET Canada. In the first quarter of 2003, an additional loss of $3 million pre-tax on disposal was recorded. Under the provisions of SFAS No. 144, ET Canada is accounted for as a discontinued operation.

Ohio Peakers - On June 30, 2003, PG&E Dispersed Generating Company (DG), an indirect subsidiary of PG&E NEG, and American Municipal Power-Ohio Inc. (Amp Ohio) entered into a contract whereby Amp Ohio will purchase DG's three Ohio generating plants, Galion, Napoleon, and Bowling Green, plus the attached spare turbines and parts and the associated rights to expand the Bowling Green and Napoleon plants (collectively referred to as the Ohio Peakers) for $7 million. The closing of this transaction is expected to occur in August 2003, after FERC approval is received. Under the provisions of SFAS No. 144, the Ohio Peakers are accounted for as assets held for sale. This requires that the assets be recorded at the lower of fair value, less costs to sell, or book value. At the same time the asset sales agreement was executed, PG&E ET and Amp Ohio executed and closed on an agreement to terminate the tolling agreement between the two parties, associated with the Bowling Green Plant. PG& amp;E ET received $5.5 million to terminate the tolling agreement. Based on the estimated proceeds from the sales agreement and including the tolling agreement termination payment, PG&E NEG recorded a pre-tax loss on disposal of $9 million in the second quarter of 2003.

The following table reflects the operating results of the combined USGenNE, Mountain View, ET Canada, and the Ohio Peakers for the three and six months ended June 30, 2003, and 2002:

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2003		2002		2003		2002
Operating Revenues	$	194	$	195	$	317	$	412
Operating Expenses	141		117		313		248
Cost of commodity sales and fuel
Operations, maintenance, and management	60		68		113		132
Depreciation and amortization	1		19		1		37
Other operating expenses	2		-		2		-
Total operating expense		204		204		429		417
Operating Income (Loss)	(10)		(9)		(112)		(5)
Interest income	8		11		15		21
Interest expense	-		(1)		(1)		(1)
Other expense, net	(2)		(4)		(6)		(6)
Income (Loss) Before Income Taxes		(4)		(3)		104		9
Income tax expense	-		(3)		-		2
Earnings (Loss) from Assets classified as   Discontinued Operations	$	(4)	$	-	$	(104)	$	7

The following table reflects the components of assets and liabilities held for sale of USGenNE and Ohio Peakers at June 30, 2003, and the combined USGenNE, Mountain View, ET Canada, and Ohio Peakers at December 31, 2002:

		Balance At
(in millions)		June 30, 2003		December 31, 2002
ASSETS		$	36	$	32
Current Assets
Cash and cash equivalents
Accounts receivable - trade		172		300
Inventory		59		82
Price risk management		177		196
Prepaid expenses, deposits and other		10		97
Total current assets held for sale		454		707
Property, Plant and Equipment		745		829
Total property, plant and equipment (1)
Accumulated depreciation		(287)		(291)
Net property, plant and equipment		458		538
Other Noncurrent Assets		286		319
Long-term receivables (2)
Intangible assets, net of accumulated amortization of $37     million and $37 million		10		20
Price risk management		24		30
Other		36		33
Total noncurrent assets held for sale		814		940
TOTAL ASSETS HELD FOR SALE			1,268		1,647
LIABILITIES			75		75
Current Liabilities
Long-term debt, classified as current
Accounts payable and Accrued expenses		59		207
Price risk management		318		331
Out-of-market contractual obligations (3)		76		86
Total current liabilities held for sale		528		699
Noncurrent Liabilities		275		272
Price risk management
Out-of-market contractual obligations (3)		465		501
Other noncurrent liabilities and deferred credit		16		20
Total noncurrent liabilities held for sale		756		793
TOTAL LIABILITIES HELD FOR SALE		1,284		1,492
NET ASSETS (LIABILITIES) HELD FOR SALE		$	(16)	$	155
(1)	Includes impairment charges made against property, plant and equipment.
(2)	USGenNE receives payments from a subsidiary of NEES, related to the assumption of power supply agreements, which are payable monthly through January 2008. The long-term receivables were recorded at the present value of the scheduled payments using a discount rate that reflects NEES' credit rating on the date of acquisition of USGenNE by PG&E NEG.
(3)	Commitments contained in the underlying Power Purchase Agreements (PPAs) by USGenNE, gas commodity and transportation agreements (collectively, the Gas Agreements), and Standard Offer Agreements acquired by USGenNE in September 1998 were recorded at fair value, based on management's estimate of either or both the gas commodity and gas transportation markets and electric markets over the life of the underlying contracts, discounted at a rate commensurate with the risks associated with such contracts. Standard Offer Agreements reflect a commitment to supply electric capacity and energy necessary for certain affiliates to meet their obligations to supply fixed-rate service. PPAs and Gas Agreements are amortized on a straight-line basis over their specific lives. The Standard Offer Agreements are amortized using an accelerated method, since the decline in value is greater in earlier years due to increasing contract pricing terms designed to reduce demand for supply service over time.

NOTE 5: PRICE RISK MANAGEMENT

As discussed in Note 3, PG&E NEG financial results will no longer be consolidated in those of PG&E Corporation following the July 8, 2003, Chapter 11 filing of PG&E NEG. Upon deconsolidation, the only risk management activities reported will be related to Utility non-trading activities.

PG&E NEG has significantly reduced its energy trading operations and is retaining limited capabilities necessary to ensure fuel procurement and power logistics for PG&E NEG's retained independent power plant operations and to serve USGenNE's needs.

Non-Trading Activities

At June 30, 2003, PG&E Corporation had cash flow hedges of varying durations associated with commodity price risk, interest rate risk, and foreign currency risk, the longest of which extend through November 2003, March 2014, and December 2004, respectively. PG&E Corporation has incurred cumulative derivative losses of $29 million on its commodity hedges, $50 million on its interest rate hedges, and $1 million on its foreign currency hedges, which are included in OCI at June 30, 2003.

PG&E Corporation's net derivative losses included in OCI at June 30, 2003, were $80 million, of which approximately $38 million is expected to be reclassified into earnings within the next 12 months based on the contractual terms of the contracts or the termination of the hedge position. The actual amounts reclassified from OCI to earnings will differ as a result of market price changes. PG&E Corporation's ineffective portion of changes in amounts of cash flow hedges was immaterial for the three and six months ended June 30, 2003, and June 30, 2002.

The schedule below summarizes the activities affecting OCI, net of tax, from derivative instruments:

(in millions)	Three months ended June 30, 2003				Three months ended June 30, 2002
	PG&E Corporation		Utility		PG&E Corporation		Utility
Derivative losses included in accumulated other    comprehensive income (loss) at beginning of period	$	(86)	$	-	$	(34)	$	-
Net loss from current period hedging transactions    and price changes		(4)		-		(9)		-
Net reclassification to earnings		10				-		-
Derivative losses included in accumulated other    comprehensive income at end of period		(80)		-		(43)		-
Foreign currency translation adjustment		-		-		(2)		-
Retirement plan remeasurement (Note 8)		(60)		(60)		-		-
Accumulated other comprehensive loss    at end of period	$	(140)	$	(60)	$	(45)	$	-

(in millions)	Six months ended June 30, 2003				Six months ended June 30, 2002
	PG&E Corporation		Utility		PG&E Corporation		Utility
Derivative losses included in accumulated other    comprehensive income (loss) at beginning of period	$	(90)	$	-	$	36	$	-
Net loss from current period hedging transactions    and price changes		(5)		-		(84)		-
Net reclassification to earnings		15		-		5		-
Derivative losses included in accumulated other    comprehensive income at end of period		(80)		-		(43)		-
Foreign currency translation adjustment		-		-		(2)		-
Retirement plan remeasurement (Note 8)		(60)		(60)		-		-
Accumulated other comprehensive loss    at end of period	$	(140)	$	(60)	$	(45)	$	-

Normally, most non-trading activity earnings are recognized on an accrual basis as revenues are earned and as expenses are incurred. For example, the effective portion of contracts accounted for as cash flow hedges have no mark-to-market effect on earnings; these contracts are presented on a mark-to-market basis on the balance sheet in price risk management (PRM) assets and liabilities and OCI. Other non-trading contracts 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.

Cash flow hedge accounting was discontinued for commodity cash flow hedge derivatives of PG&E NEG on January 1, 2003. Accordingly, prospective changes in the fair value of these discontinued cash flow hedge derivatives affect PG&E NEG's earnings on a mark-to-market basis along with the ineffective portion of all cash flow hedges. PG&E NEG has certain non-trading derivative contracts that do not qualify for cash flow hedge accounting or the normal purchases and sales exception to SFAS No. 133. These derivatives are reported in earnings on a mark-to-market basis. These contracts consist primarily of those derivative commodity contracts for which normal purchases and sales treatment was disallowed upon PG&E NEG's implementation of DIG C15 and C16 effective April 1, 2002.

PG&E NEG's pre-tax earnings include losses of $18 million and gains of $32 million for the three- and six-month periods ended June 30, 2003, related to commodity hedges, previously deferred in OCI, after it became probable that the forecasted transactions will not occur.

At June 30, 2003, the Utility had cash flow hedges associated with natural gas commodity price risk. These contracts are presented at fair value on the Utility's Consolidated Balance Sheets in PRM assets and regulatory liabilities. At June 30, 2002, the Utility did not have any cash flow hedges.

The Utility has certain 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.

Trading Activities

Unrealized gains and losses from trading activities, including the reversal of unrealized gains and losses previously recognized on contracts that go to settlement or delivery, are presented on a net basis in operating revenues. Realized gains and losses from trading activities also are presented on a net basis in operating revenues, beginning in the third quarter of 2002, as more fully described in Note 1 of the Notes to the Consolidated Financial Statements.

Gains and losses on trading contracts affect PG&E Corporation's gross margin in the accompanying PG&E Corporation Consolidated Statements of Operations on a mark-to-market basis. Settlement or delivery on a contract generally does not result in incremental net income recognition because the profit or loss on a contract is recognized in income on a mark-to-market basis during the periods before settlement occurs.

Gains and losses on trading contracts affect PG&E Corporation's cash flow when these contracts are settled. Net realized gains reported in the table below primarily reflect the net effect of contracts that have been settled in cash. Net realized gains also include certain non-cash items, including amortization of option premiums that were paid or received in cash in earlier periods, but are considered realized when the related options are exercised or expired.

PG&E Corporation's net gains (losses) on trading activities are as follows:

	Three months ended				Six months ended
	June 30,				June 30,
(in millions)	2003		2002		2003		2002
Trading activities:
Unrealized losses, net	$	(41)	$	(48)	$	(33)	$	(53)
Realized gains (losses), net	(7)		34		(40)		78
Total	$	(48)	$	(14)	$	(73)	$	25

Price Risk Management Assets and Liabilities

PRM assets and liabilities on the accompanying PG&E Corporation Consolidated Balance Sheets reflect the aggregation of the fair values of outstanding contracts. These fair values are calculated on a mark-to-market basis for contracts that will be settled in future periods. PRM assets and liabilities at June 30, 2003, include amounts for trading and non-trading activities, as described below:

	PRM Assets				PRM Liabilities				Net Assets (Liabilities)
(in millions)	Current		Noncurrent		Current		Noncurrent
PG&E NEG
Trading activities	$	230	$	224	$	(213)	$	(269)	$	(28)
Non-trading activities		39		83		(14)		(5)		103
Utility
Non-trading activities		11		-		-		-		11
Total consolidated PRM assets and   liabilities	$	280	$	307	$	(227)	$	(274)	$	86

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; notes receivable included in Other Noncurrent Assets - Other; PRM assets; and Assets Held For Sale on the Consolidated Balance Sheets of PG&E Corporation and the Utility, as applicable. PG&E Corporation and the Utility conduct business primarily with customers or vendors, referred to as counterparties, in the energy industry. These counterparties include other 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 PG&E Corporation's and the Utility's overall exposure to credit risk because their counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions.

PG&E Corporation and the Utility manage their credit risk in accordance with the PG&E Corporation Risk Management Policy. This established processes for assigning credit limits to counterparties before entering into agreements with significant exposure to PG&E Corporation and the Utility. These processes include an evaluation of a potential counterparty's financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually.

Credit exposure is calculated daily, and in the event that exposure exceeds the established limits, PG&E Corporation and the Utility take immediate action to reduce the exposure, or obtain additional collateral, or both. Further, PG&E Corporation and the Utility rely 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.

PG&E Corporation and the Utility calculate 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 period ended June 30, 2003, PG&E Corporation's credit risk decreased, as compared to December 31, 2002, primarily due to contract terminations with PG&E NEG counterparties. During the period ended June 30, 2003, the Utility's credit risk decreased, as compared to December 31, 2002, primarily due to the receipt of payment from a previously terminated contract with a counterparty.

During the three- and six-month periods ended June 30, 2003, PG&E Corporation and the Utility recognized no losses due to the contract defaults or bankruptcies of counterparties.

At June 30, 2003, PG&E Corporation had no single counterparty that represented greater than 10 percent of PG&E Corporation's net credit exposure. At June 30, 2003, the Utility had one investment grade counterparty that represented 17 percent of the Utility's net credit exposure and one below-investment grade counterparty that represented 11 percent of the Utility's net credit exposure.

The schedule below summarizes PG&E Corporation's and the Utility's credit risk exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis), as well as PG&E Corporation's and the Utility's credit risk exposure to counterparties with a greater than 10 percent net credit exposure, at June 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
At June 30, 2003
PG&E Corporation		$	710	$	97	$	613		-	$	-
Utility (3)		220		55		165		2		46
At December 31, 2002
PG&E Corporation		$	1,165	$	195	$	970		-	$	-
Utility (3)		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, model, or credit reserves.
(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)	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 gas and electricity to millions of residential and small commercial customers.

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

Credit Quality (1)		Net Credit Exposure(2)		Percentage of Net Credit Exposure
(in millions)
At June 30, 2003
PG&E Corporation
Investment grade(3) (4)		$	363	59%
Noninvestment grade			120	20%
Not rated(4)			130	21%
Total		$	613	100%
Utility
Investment grade(3) (4)		$	101	61%
Noninvestment grade			64	39%
Not rated(4)			-	-
Total		$	165	100%
At December 31, 2002
PG&E Corporation
Investment grade(3) (4)		$	700	72%
Noninvestment grade			205	21%
Not rated(4)			65	7%
Total		$	970	100%
Utility
Investment grade(3) (4)		$	111	63%
Noninvestment grade			64	37%
Not rated(4)			-	-
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.
(4)	Most counterparties with no ratings are governmental authorities that are not rated through publicly available information, but which PG&E Corporation has assessed as equivalent to investment grade based upon an internal assessment of credit quality. These are designated as "investment grade" in the above. Other counterparties with no rating obtainable through publicly available information, are designated as "not rated" above, but are subject to an internal assessment of their credit quality and an internal credit rating designation.

PG&E Corporation has regional concentrations of credit exposure to counterparties that conduct business primarily throughout North America. 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 nonperformance from these customers is not considered likely. Reserves for uncollectible accounts receivable are provided for the potential loss from nonpayment by these customers based on historical experience. At June 30, 2003, the Utility had a net regional concentration of credit exposure totaling $165 million to counterparties that conduct business primarily throughout North America.

NOTE 6: COMMITMENTS AND CONTINGENCIES

PG&E Corporation has 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 PG&E NEG's operating activities. These commitments are discussed more fully in the PG&E Corporation's and Utility's combined 2002 Annual Report on Form 10-K, as amended. The following summarizes PG&E Corporation's, the Utility's, and PG&E NEG'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. The total demand charges that the Utility will pay each year may change due to changes in tariff rates. These agreements include provisions for payment of fixed demand charges for reserving firm pipeline capacity as well as volumetric transportation charges.

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

(in millions)
2003	$	479
2004		276
2005		84
2006		26
2007		7
Thereafter		-
Total	$	872

Since the Utility is in Chapter 11 and its credit ratings are below investment grade, the Utility uses several different credit arrangements for the purpose of purchasing natural gas. The Utility has a $10 million standby letter of credit and has pledged its gas customer accounts receivable. The core gas inventory may be pledged but only if the Utility's gas customer accounts receivable are less than the amount that the Utility owes to the gas suppliers. Through June 30, 2003, the accounts receivable pledge has been sufficient. The CPUC authorized the Utility to pledge its gas accounts receivable and core 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.

At June 30, 2003, the pledged amount of gas accounts receivable was $220 million.

Transmission Control Agreement - The Utility entered into a Transmission Control Agreement (TCA) with the ISO and others. 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 SCE and San Diego Gas & Electric Company, assign control and operation of their electric transmission systems to the ISO. In addition, as a party to the TCA, the transmission owners are responsible for the costs of the Reliability Must-Run (RMR) Agreements between the ISO and owners of the plants subject to RMR contracts (RMR plants). Under the RMR Agreements, RMR plants must remain available to generate electricity when needed for transmission system reliability upon the ISO's demand.

At June 30, 2003, the ISO has RMR agreements that obligate the Utility for approximately $911 million during the period July 1, 2003, to June 30, 2005.

It is possible that the Utility may receive a refund of RMR costs previously paid to the ISO. In June 2000, an Administrative Law Judge (ALJ) at the FERC issued an initial decision that would require the subsidiaries of the Mirant Corporation (Mirant) that are parties to three RMR contracts with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments for availability of Mirant's generating units under the RMR contracts. If the FERC were to affirm the ALJ's initial decision, the Utility would expect refunds, with interest, of approximately $300 million. Any refunds received would be used to reduce previously under-collected transition and procurement costs or to lower future reliability services rates depending on the time period covered by the refunds. 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 the outcome of the FERC's decision will be, and the amount of any refunds, which may be impacted by Mirant's Chapter 11 filing, the Utility will ultimately receive.

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 June 2003, the CPUC issued a decision that requires each IOU to increase procurement of renewable energy by at least 1 percent per year. By the end of 2017, each IOU must be procuring at least 20 percent of its total electricity from renewable resources. The decision states that the Utility is not obligated to procure additional renewable energy until it is creditworthy and that the Utility will accumulate an Annual Procurement Target (APT) based on 1 percent of retail sales, each year, starting in 2003, until it receives an investment grade credit rating. When the Utility receives an investment grade credit rating it will be required to enter into procurement 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 Utilit y 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 kilowatt-hour (kWh), subject to an annual penalty cap of $25 million.

PG&E NEG

Letters of Credit

In addition to the outstanding balances under the credit facilities described in Note 3, PG&E NEG and certain subsidiaries are required to reimburse amounts drawn under letters of credit issued by financial institutions under certain financing facilities. As a result of PG&E NEG's Chapter 11 filing, the financial institutions are no longer obligated to provide letters of credit facilities. The following table lists the various letter of credit facilities:

(in millions) Borrower	Maturity	Letter of Credit Capacity		Letter of Credit Outstanding June 30, 2003
PG&E NEG	8/03	$	115	$	115
USGenNE	8/03		25		13
PG&E Gen	12/04		6		6
PG&E ET	9/03		19		19
PG&E ET	11/03		35		25

Tolling Agreements

PG&E ET entered into tolling agreements with several counterparties under which, at its discretion, PG&E ET supplied the fuel to the power plants and then sold the plant's output in the competitive market. Payments to counterparties would be reduced if the plants did not achieve agreed-upon levels of performance. The face amount of PG&E NEG's and its subsidiaries' guarantees relating to PG&E ET's tolling agreements is approximately $565 million. PG&E ET entered into tolling agreements with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount of up to $140 million, (2) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place, (3) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $175 million, and (4) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million. On July 8, 2003, PG&E ET petitioned the Bankruptcy Court to reject all remaining tolling agr eements. On August 6, 2003, the Bankruptcy Court approved PG&E ET's motion and the Liberty, Southaven, and Caledonia tolling agreements are now terminated.

Under each tolling agreement, determination of the termination payment is based on a formula that takes into account a number of factors including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. The Bankruptcy Court may resolve any damages claim or permit such arbitration to proceed.

DTE-Georgetown, LLC - On June 26, 2003, PG&E GTN, PG&E Energy Trading - Power, LP (PGET), and DTE-Georgetown, LLC (DTE) entered into a termination agreement that terminated a tolling agreement between DTE and PGET dated May 23, 2000. In consideration for a payment of approximately $30 million by PGET, the termination agreement releases and discharges PGET from any and all obligations under the tolling agreement and PG&E GTN from any and all obligations under its guarantee of PGET's obligations, subject to restoration of PG&E GTN's guarantee obligation in the limited event that DTE may be required to disgorge amounts received from PGET. Under the tolling agreement, PGET would have had to make capacity payments totaling approximately $64 million over the next seven years.

Liberty - On August 6, 2003, the Bankruptcy Court approved PG&E ET's motion to reject the Liberty tolling agreement, and that agreement is now terminated. Whether and to the extent either Liberty or PG&E ET may be found liable for termination payments under the Liberty tolling agreement is subject to dispute. If liability is established and PG&E ET is responsible for termination payments to Liberty, PG&E GTN will be the primary guarantor for any amounts due to Liberty. Under the terms of the guarantee to Liberty, PG&E GTN is potentially liable for termination payments up to the maximum amount of the guarantee, $140 million. On July 22, 2003, Liberty issued a $4.4 million payment demand to PG&E GTN under the guarantee, ostensibly for a capacity payment due from PG&E ET to Liberty arising prior to PG&E ET's filing for bankruptcy protection. In addition, on July 30, 2003, Liberty sent an invoice for a termination payment of approximately $177 million to PG&a mp;E ET.

Southaven and Caledonia Tolling Agreements - PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, and Caledonia dated September 30, 2000, under which PG&E ET was required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment grade as defined in the tolling agreement. The amount of the guarantee does not exceed $175 million for Southaven and $250 million for Caledonia. By letter dated August 31, 2002, Southaven and Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment grade as defined in the tolling agreement, and because PG&E ET had failed to provide, within 30 days from the downgrade, substitute credit support that meets the requirement of the tolling agreement. Southaven and Caledonia have the right to te rminate the agreement and seek a termination payment. In addition, PG&E ET provided Southaven and Caledonia with a notice of default respecting Southaven's and Caledonia's performance under the tolling agreement and concerning the inability of the facility to inject its output into the local grid. Southaven and Caledonia have not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

On February 7, 2003, Southaven and Caledonia filed emergency petitions to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court of Montgomery County, Maryland. On March 3, 2003, the court issued an order ruling that PG&E ET must continue to perform under the agreements. PG&E ET appealed this decision to an intermediate Maryland appellate court. However, on April 8, 2003, the highest appellate court in Maryland issued on its own motion an order taking jurisdiction of the appeal. This action is currently stayed as a result of PG&E ET's Chapter 11 filing on July 8, 2003. The Southaven and Caledonia tolling agreements were the subject of a motion to reject filed by PG&E ET with the Bankruptcy Court on July 8, 2003. On August 6, 2003, the Bankruptcy Court granted PG&E ET's motion, and terminated the Southaven and Caledonia tolling agreements.

Contingencies

Utility

The Utility has significant gain and loss contingencies related to its Chapter 11 filing.

Recovery of Transition Costs and Surcharge Revenues

As a result of frozen rates, at December 31, 2000, the Utility had accumulated a total of approximately $4.1 billion, after-tax, in under-collected purchased power and generation-related transition costs. This amount was charged to earnings at that time because the Utility could no longer conclude that such costs were probable of collection through regulated rates. In 2001 and 2002, as a result of stabilized wholesale electricity prices and the CPUC-authorized surcharges discussed below, the Utility's total generation-related electric revenues were greater than its generation-related costs, resulting in the partial recovery of under-collected purchased power and generation-related transition costs that were previously written off. As of December 31, 2002, the outstanding balance of the under-collected purchased power and generation-related transition costs was $2.2 billion, after-tax. During the first quarter of 2003, generation-related costs exceeded generation-related revenues due to lower wint er consumption and lower winter rates. During the second quarter of 2003, generation-related revenues returned to levels in excess of generation-related costs. As of June 30, 2003, the outstanding balance of the Utility's under-collected purchased power and generation-related transition costs amounted to $2.1 billion, after-tax, excluding interest and other Chapter 11-related costs. Generation-related costs in excess of generation-related revenues continue to be expensed as they are incurred. Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would agree to establish a new regulatory asset to restore the Utility to financial health (see Note 2). The balances in the Utility's transition cost balancing account as of January 1, 2004, would have no further impact on the Utility's retail electric rates and would be subject to no further review by the CPUC except for verification of recorded balances.

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 another IOU, 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, $0.03, and $0.005 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 proceed ing (discussed in Note 2). As such, the Utility has not recorded a regulatory liability or a refund reserve for these surcharge revenues, or any portion thereof, in its financial statements. From January 2001 to June 30, 2003, the Utility recognized total surcharge revenues of $6.5 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 settlement defines headroom as the Utility's total net after-tax income reported under 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 settlement notes tha t 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 settlement agreement provides that if headroom revenues accrued by the Utility during 2003 are greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom revenues are less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in rates. Headroom revenues for the six months ended June 30, 2003, were $237 million, pre-tax, as calculated under the terms of the proposed settlement agreement.

The Utility's ultimate recovery of its previously written-off under-collected purchased power and generation-related transition costs if the proposed settlement agreement and Settlement Plan are not implemented and the validity of the CPUC's agreements under the proposed settlement agreement regarding headroom, surcharge and base revenues collected by the Utility through and including December 31, 2003, may depend upon the California Supreme Court's consideration of questions certified to it by the Ninth Circuit regarding the legality of recovery of under-collected costs by SCE under a settlement and stipulated federal court judgment with the CPUC. The CPUC represented to the court that, in part, as a result of California (AB) 6X, which prevented the Utility from divesting generation assets, it has the authority to allow the Utility and SCE to recover under-collected purchased power and generation-related transition costs beyond the end of the rate freeze. The settlement reached by the CPUC and SCE provides that the CPUC would maintain SCE's rates at their current levels (beyond the end of the rate freeze) until the earlier of the date that SCE recovered its transition costs or December 31, 2003. Several entities, including TURN, have challenged this settlement and the ratemaking adopted by the CPUC to implement the settlement, arguing, among other things, that the recovery of SCE's under-collected costs in retail rates under the settlement violates the provisions of AB 1890 prohibiting post-freeze recovery of transition and procurement costs. Oral argument occurred before the California Supreme Court on May 27, 2003, and it is expected that the Court will issue a ruling by August 27, 2003.

Even if the California Supreme Court were to rule that the SCE settlement violates state law and, therefore, California IOUs are not permitted to recover their procurement and transition costs after the end of the rate freeze, such a ruling would not affect the Utility's claim that it has a right to recover such costs under the federal filed rate doctrine, which is currently pending before the federal courts. Under the proposed settlement agreement, on or as soon as practicable after the latter of the effective date of the Settlement Plan or the date that CPUC approval of the proposed settlement agreement is no longer subject to appeal, the Utility would dismiss with prejudice the filed rate case.

Further, PG&E Corporation and the Utility believe that, even if the California Supreme Court finds the SCE settlement violates state law, there are independent legal and factual reasons under which the proposed settlement agreement and the Settlement Plan would still be valid under state and federal law. The effectiveness of the Settlement Plan is not conditioned on receiving a favorable ruling in the SCE case by the California Supreme Court.

If the Settlement Plan contemplated in the proposed settlement agreement in the Utility's Chapter 11 proceeding is not implemented, it is possible that at some future date the CPUC, either in response to certain judicial decisions, or on its own initiative, may change its interpretation of law or otherwise seek to change the Utility's overall retail electric rates retroactively. As stated above, the Utility has not provided reserves for potential refunds of any of these surcharge revenues as of June 30, 2003. If the CPUC requires the Utility to refund any of these revenues in the future, the Utility's earnings could be materially affected.

In July 2003, a CPUC Commissioner issued a proposed decision that proposes to find that the retail electric rate freeze ended on January 18, 2001. The proposed decision also provides that the CPUC would determine the extent and disposition of costs previously defined as uneconomic, transition or stranded, in a separate proceeding. 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 settlement agreement and the implementation of the Settlement Plan. The Utility cannot predict the ultimate outcome of this proceeding.

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. This decision required the Utility, along with the other IOUs, to begin performing all the day-to-day scheduling, dispatch, and administrative functions associated with the DWR contracts allocated to the IOUs' respective resource portfolios by January 1, 2003. The DWR retains legal and financial responsibility for these contracts.

Under the proposed settlement agreement, the Utility would agree to accept an assignment of or to assume legal and financial responsibility for the DWR contracts only if (1) the Utility receives a long-term issuer credit rating of at least A from S&P and an issuer credit rating of at least A2 from Moody's after giving effect to such assignment or assumption, (2) the CPUC first makes a finding that the DWR allocated contracts are just and reasonable, and (3) the CPUC first acts to ensure that the Utility receives full and timely rate recovery of all costs of the DWR contracts over their life without further review. The CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law. The State of California has stated publicly that it does not intend to transfer full legal title of, and responsibility for, the DWR electricity contracts to the IOUs until they are in a position where they will be financially able to absorb the contracts. However, if the proposed settlement agreement is not approved and either the State of California or the CPUC grants the DWR the authority to transfer legal title of the DWR contracts to the Utility without having first met the Utility's conditions, the Utility's results of operations could be adversely affected.

Nuclear Insurance

The Utility has several types of nuclear insurance for its Diablo Canyon Power Plant (DCPP) and Humboldt Bay Power Plant (HBPP). 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. Under this insurance, if any nuclear generating facility insured by NEIL suffers severe losses, the NEIL Board of Directors could require the Utility to pay additional annual premiums of up to $32 million for DCPP to cover property damages and business interruption and up to $1.4 million for HBPP to cover property damages.

Under federal law, the Price-Anderson Act (Act), public liability claims from a nuclear incident are limited to $9.5 billion. As required by the Act, the Utility has purchased the maximum available public liability insurance of $300 million for DCPP. The balance of the $9.5 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Act, secondary financial protection is required for all reactors of 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 $88 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 Utility has two nuclear reactors of over 100 MW, the Utility may be assessed up to $176 million per incident, with payments 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.

Additionally, the Utility has purchased $53.3 million of private liability insurance for HBPP and has a $500 million indemnification from the Nuclear Regulatory Commission (NRC) for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of private liability insurance for HBPP.

Workers' Compensation Security

The Utility is self-insured for workers' compensation. The Utility must deposit collateral with the State 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, or securities. The Utility currently provides 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 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, towards the $365 million amount of collateral. Three additional active surety bonds totaling $180 million make up the Utility's collateral. At June 30, 2003, the canceled bonds have not impacted the Utility's self-insured status under California law. PG&E Corporation has guaranteed the Utility's reimbursement obligation associated with these surety bonds and the Utility's underlying obligation to pay workers' compensation claims.

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 a specific recovery method. In the decisions ordering the creation of these balancing accounts, the CPUC indicated that the recovery method of 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 June 30, 2003, the reserve associated with these balancing accounts was approximately $220 million.

DWR Revenue Requirement

Because the Utility acts as a collection agent for the DWR, amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues. Until the CPUC modifies the current frozen rate structure or until the approval of the proposed settlement agreement and new rates under that settlement are implemented, changes to the DWR's 2001, 2002, or 2003 revenue requirement may materially affect the Utility's future earnings.

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 cost associated with the DWR contracts allocated to the Utility's customers effective 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. (The December 2002 operating order required the Utility to perform the operational, dispatch, and administrative functions for the DWR's allocated contracts beginning on January 1, 2003.) The operating agreement provides that the Utility will begin passing through additional revenues to the DWR consistent with the DWR's October 2002 and March 2003 requests for amendments to the formula that determines the amount of remittances to the DWR contained in the May 2002 servicing order but subject to the outcome of the CPUC's consideration of the DWR's requests. As of June 30, 2003, the Utility had accrued an additional $516 million, pre-tax, obligation for pass-through revenues to the DWR. The Utility had accrued $369 million, pre-tax, at December 31, 2002, and $539 million, pre-tax, at March 31, 2003 for these additional pass-through revenues to the DWR. During the second quarter of 2003, the Utility remitted $74 million of these pass-through revenues to the DWR and accrued an additional $51 million. The ultimate remittance of the $516 million amount accrued as of June 30, 2003, depends upon whether the CPUC grants the DWR's request for changes to the May 2002 servicing order (which was revised in December 2002) and whether such changes would be retroactive to January 2001, the date that the DWR began purchasing power for the Utility's customers.

In July 2003, the DWR submitted a supplemental 2003 revenue requirement to the CPUC reducing the amount of the total 2003 statewide power charge-related revenue the DWR was anticipating to receive by approximately $1 billion. The CPUC is responsible for determining how to allocate the reduced revenue requirement among the customers of the three California IOUs. The requested reduction expressly assumes that the Utility would remit an additional estimated cash payment of $539 million, which was accrued as of March 31, 2003, to the DWR in 2003. The ALJ in this proceeding indicated that the $539 million assumed remittance amount is an estimate and not a final number. The ALJ also indicated that, in connection with the proposed 2003 DWR revenue requirement reduction, the CPUC may consider reducing utility rates overall in order to pass through the savings to customers. The CPUC expects to consider a proposed decision during the third quarter of 2003. On August 1, 2003, another CPUC ALJ issued a draft decision that, if approved by the CPUC, would modify the May 2002 and December 2002 DWR servicing orders to require the Utility to remit an additional cash payment to the DWR for the period retroactive to January 2001 as discussed above. The draft decision would not specify the amount to be remitted but instead defers the issue to the 2003 DWR supplemental revenue requirement proceeding, where offsetting reductions to the DWR's revenue requirements and remittances for 2003 are being considered. The draft decision would not determine whether the Utility should pay interest on the additional payment, but would defer to both the DWR and the Utility to resolve the issue, subject to CPUC determination if the parties cannot agree. The draft decision is subject to comment by parties before being considered by the CPUC. A separate proceeding will consider a revision or adjustment for the revenue requirements remitted to the DWR for 2002 and 2001 costs. At that time, the CPUC may also consider a revision or adjustment to the allocation of the DWR's 2003 revenue requirement. The Utility cannot predict the ultimate outcome of this matter.

The Utility has a lawsuit pending in a California court, asking that the DWR be precluded from imposing its revenue requirements on the Utility and its customers until the DWR can demonstrate that its revenue requirements are "just and reasonable," as legally required. The lawsuit is scheduled to be considered by the court during the third or fourth quarter of 2003.

PG&E NEG

Guarantees

PG&E NEG and certain subsidiaries have provided guarantees as of June 30, 2003, to approximately 96 counterparties in support of PG&E ET's energy trading and non-trading activities related to PG&E NEG's merchant energy portfolio in the face amount of $1.1 billion. During the second quarter, due to wind down of the trading operations, PG&E NEG and its subsidiaries have canceled guarantees amounting to $1.5 billion. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully used at any time. The amount of such exposure varies daily depending on changes in market prices and net changes in position. With its Chapter 11 filing on July 8, 2003, PG&E ET defaulted on numerous trading agreements. The amounts due as a result of these defaults will be determined and resolved in the context of PG&E ET's Chapter 11 filing.

Other Guarantees

PG&E NEG provided guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of these guarantees relate to performance under certain construction contracts. These guarantees represent guarantees of subsidiary obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG's power plants and pipelines. These guarantees are described below.

PG&E NEG has issued guarantees to construction financing lenders for the performance of the contractors building the Harquahala and Covert generating projects for up to $555 million. Additionally, PG&E NEG has issued $100 million of guarantees to the construction contractor of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements. As a result of the settlement of the Shaw Litigation, these guarantees have been terminated.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a wholly owned subsidiary, Attala Energy Company, LLC, has entered into with another wholly owned subsidiary, Attala Generating.

The balance of the guarantees are for commitments undertaken by PG&E NEG or subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.

PG&E Corporation

A claim has been asserted on behalf of PG&E NEG's estate that PG&E NEG is entitled to be compensated for any tax savings achieved by PG&E Corporation as a result of the incorporation of PG&E NEG's losses and deductions in PG&E Corporation's consolidated federal tax return under an alleged implied tax sharing agreement between PG&E Corporation and PG&E NEG 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 PG&E NEG and its subsidiaries, of which approximately $361 million is attributable to losses and deductions related to PG&E NEG and its subsidiaries that were incorporated into PG&E Corporation's 2002 consolidated federal income tax return. It has been asserted that PG&E NEG has a direct interest in $361 million of the funds received by PG&E Corpo ration at a minimum. PG&E Corporation denies that any tax sharing agreement, whether implied or express, ever existed and denies that it has any obligation to compensate PG&E NEG 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. Nevertheless, any adjudication of PG&E NEG's claim and any use or disposition of such funds will be subject to resolution in PG&E NEG's bankruptcy proceeding. Consequently, until the dispute is resolved in the Chapter 11 proceeding, PG&E Corporation is treating $361 million of the amount received by PG&E Corporation as restricted cash.

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 Note 3 above, effective July 8, 2003, PG&E Corporation no longer will consolidate PG&E NEG's financial results and will begin accounting for its investment in PG&E NEG using the cost method.

In addition, 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

Utility

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 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 a range of likely clean-up costs can be reasonably estimated. The Utility reviews its remediation liability on a quarterly basis for each site that 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 lower end of this range.

The Utility had an undiscounted environmental remediation liability of $302 million at June 30, 2003, and $331 million at December 31, 2002. During the first half of the year, the liability was reduced by $29 million primarily due to a reassessment of the estimated cost of remediation. The $302 million accrued at June 30, 2003, includes (1) $105 million related to the pre-closing remediation liability associated with divested generation facilities, and (2) $197 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 are either owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former gas plant sites. Of the $302 million environmental remediation liability, the Utility has recovered $155 million through rates charged to its customers, and expects to recover approximatel y $93 million of the balance in future rates. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refunds to ratepayers. The Utility also is recovering its costs from insurance carriers and from other third parties whenever it is possible.

The cost of the hazardous substance remediation ultimately undertaken by the Utility 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 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.

On June 28, 2001, the Bankruptcy Court authorized the Utility to continue its hazardous waste remediation program and to expend (1) up to $22 million in hazardous substance remediation programs and procedures in each calendar year in which the Chapter 11 case is pending, and (2) any additional amounts in emergency situations involving post-petition releases or threatened releases of hazardous substances subject to the Bankruptcy Court's specific approval.

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 normal 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. 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 state's claims seeking specific cash recoveries are unenforceable.

Moss Landing - In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water and organic debris from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. A settlement has been reached with the Central Coast Board, under which the Utility would pay a total of $5 million to be used for environmental projects. No civil penalties would be paid under the settlement. The Central Coast Board voted to accept the settlement in December 2002, and the Utility has obtained authorization from the Bankruptcy Court to enter into the final settlement agreement. The parties have signed the settlement agreement, which was incorporated into a consent decree entered in the California Superior Court on May 9, 2003. The California Attorney General has filed a claim in the Utility's Chapter 11 case to preserve the Central Coast Board's claim. The Utility currently 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 of results of operations.

Diablo Canyon - The Utility's Diablo Canyon employs a "once-through" cooling water system, which is regulated under an NPDES permit issued by the Central Coast Board. This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above 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, Diablo Canyon'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 plant protects beneficial uses and that the intake technology reflects the "best technology available" under Section 316(b) of the Federal Clean Water Act. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement. On May 5, 2003, the Bankruptcy Court authorized the Utility to sign the final settlement agreement. 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 settlement to become effective, among other things, the Cen tral Coast Board must renew Diablo Canyon's NPDES permit. However, at its July 10, 2003, meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement accepted in March 2003 and the Central Coast Board requested its staff to develop additional information on possible mitigation measures.

The California Attorney General has filed a claim in the Utility's Chapter 11 proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with Diablo Canyon'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.

PG&E NEG

In May 2000, USGenNE, an indirect subsidiary of PG&E NEG, received an Information Request from the U.S. Environmental Protection Agency (EPA), pursuant to Section 114 of the Federal Clean Air Act (CAA). The Information Request asked USGenNE to provide certain information relative to the compliance of its Brayton Point and Salem Harbor plants with the CAA. No enforcement action has been brought by the EPA to date. USGenNE has had preliminary discussions with the EPA to explore a potential settlement of this matter. It is not possible to predict at this point whether any such settlement will occur or, in the absence of a settlement, the likelihood of whether the EPA will bring an enforcement action.

As a result of the EPA Information Request and environmental regulatory initiatives by the Commonwealth of Massachusetts, USGenNE is exploring ways to achieve significant reductions of sulfur dioxide (SO₂) and nitrogen oxide (No_x) emissions. Additional requirements for the control of mercury and carbon dioxide emissions also will be forthcoming as part of these regulatory initiatives. Management believes that USGenNE would meet these requirements through installation of controls at the Brayton Point and Salem Harbor plants, and estimates that capital expenditures on these environmental projects could approximate $426 million over the next four years. These estimates are currently under review and it is possible that actual expenditures may be higher. Based on an emission control plan filed for Brayton Point under the regulations implementing these initiatives, the Massachusetts Department of Environmental Protection (DEP) ruled that Brayton Point is required to meet the newer, mo re stringent emission limitations for SO₂ and No_x by 2006.

On June 19, 2003, USGenNE, the DEP, the City of Salem, and various environmental/citizen groups entered into an Administrative Consent Order (ACO) to resolve a number of administrative appeals regarding matters related to the Massachusetts air regulations for the Salem Harbor Station. The ACO's terms will constitute compliance with the NO_x and SO₂ provisions of the regulations. The ACO describes generally how USGenNE will comply with these regulations and takes into account the need for reliable electricity supplies, the financial uncertainties surrounding USGenNE, the fiscal uncertainties of the City of Salem, and the economic risks to the workers at the facility. USGenNE has represented to the parties that USGenNE does not have the ability to finance the capital improvements it has proposed to achieve compliance, and that, as a result, such funding must be provided by public sources unaffiliated with USGenNE. The ACO also requires USGenNE to implement certain near-term pollutio n control measures. The ACO was submitted to the ALJ, together with a motion to enter to ACO as a final resolution of the two adjudicatory proceedings.

Various aspects of the DEP's regulations allow for public participation in the process through which the DEP determines whether the 2004 or 2006 deadline applies and approves the specific activities that USGenNE will undertake to meet the new regulations. A number of local environmental groups are now participants in this process.

The EPA is required under the CAA to establish new regulations for controlling hazardous air pollutants from combustion turbines and reciprocating internal combustion engines. Although the EPA has yet to propose the regulations, the CAA required that they be promulgated by November 2000. Another provision in the CAA requires companies to submit case-by-case Maximum Achievable Control Technology (MACT) determinations for individual plants if the EPA fails to finalize regulations within 18 months past the deadline. The EPA has extended this deadline through previous rulemakings. In late 2002, the EPA proposed a rule that would require the case-by-case MACT applications to be submitted by October 30, 2003, if the EPA has not promulgated a MACT rule as of that date. The EPA intends to finalize the MACT regulations before this date, thus eliminating the need for the plant-specific permits. PG&E NEG will not be able to accurately quantify the economic impact of the future regulations until more detail s are available through the rulemaking process.

PG&E NEG's existing power plants are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE (Salem Harbor, Manchester Street, and Brayton Point) are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and all three facilities are continuing to operate under existing terms and conditions until new permits are issued. On July 22, 2002, the EPA and the DEP issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay.

Based on its initial review of the draft permit, USGenNE believes that the draft permit is excessively stringent. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $248 million through 2006, but this is a preliminary estimate. There are various administrative and judicial proceedings that must be completed before the draft NPDES permit for Brayton Point becomes final, and these proceedings are not expected to be completed during 2003. In addition, the EPA, as well as local environmental groups, previously expressed concern that the metal vanadium is not addressed at Brayton Point or Salem Harbor under the terms of the old NPDES permits. However, if the EPA does insist on including vanadium in the NPDES permit, USGenNE may have to spend a significant amount of cost to comply with such a provision. In addition, it is possible that the new permits for Salem Harbor and Manchester Street also may contain more stringent limitations than prior permits and that the cost to comply with the new permit conditions could be greater than the current estimate of $4 million. Lastly, the issuance of any final NPDES permits may be affected by the EPA's proposed regulations under Section 316(b) of the Clean Water Act, as described below.

On March 27, 2002, the Rhode Island Attorney General notified USGenNE of his belief that Brayton Point "is in violation of applicable statutory and regulatory provisions governing its operations..." including "protections accorded by common law" respecting discharges from the facility into Mount Hope Bay. He stated that he intends to seek judicial relief "to abate these environmental law violations and to recover damages..." within the next 30 days. PG&E NEG believes that Brayton Point is in full compliance with all applicable permits, laws, and regulations. The complaint has not yet been filed or served. In early May 2002, the Rhode Island Attorney General stated that he did not plan to file the action until the EPA issues a draft Clean Water Act NPDES permit for Brayton Point. The EPA issued this draft permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing this matter until he reviews USGenNE's response to the draft permit which was submi tted on October 4, 2002. It is uncertain whether the Rhode Island Attorney General will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E NEG's financial condition or results of operations.

On April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing power generation facilities using over 50 million gallons per day typically including some form of "once-through" cooling. Brayton Point, Salem Harbor, and Manchester Street are among an estimated 539 plants nationwide that would be affected by this rulemaking. The proposed rule calls for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. The final regulations are scheduled to be promulgated in February 2004. The extent to which they may require additional capital investment will depend on the timing of the NPDES permit proceedings for the affected facilities.

During April 2000, an environmental group served USGenNE and other PG&E NEG subsidiaries with a notice of its intent to file a citizen's suit under the Resource Conservation Recovery Act. In September 2000, PG&E NEG signed a series of agreements with the DEP and the environmental group to resolve these matters that require PG&E NEG to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. PG&E NEG began the activities during 2000 and is expected to complete them in 2003. PG&E NEG incurred expenditures related to these agreements of $4.7 million in 2002, $2.6 million in 2001, and $5.7 million in 2000. In addition to the costs previously incurred, PG&E NEG maintains a reserve in the amount of $5.4 million relating to its estimate of the remaining expenditures to fulfill its obligations under these agreements. PG&E NEG has deferred costs associated with capital expenditures and has set up a receivable account for amount s it believes are probable of recovery from insurance companies.

PG&E NEG believes that it may be required to spend up to approximately $678 million, excluding insurance proceeds, through 2008 for environmental compliance to continue operating these facilities. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against PG&E NEG. PG&E NEG has not made any commitments to spend these amounts. In the event PG&E NEG does not spend or is unable to spend because of liquidity constraints amounts needed in order to comply with these requirements, PG&E NEG may not be able to continue to operate one or all of these facilities.

Global Climate Change

Global climate change is a significant environmental issue that is likely to require sustained global action and investment over many decades. The Utility and PG&E NEG have been engaged on the climate change issue for several years and are working with others on developing appropriate public policy responses to this challenge. The Utility and PG&E NEG have continuously assessed the financial and operational implications of this issue; however, the outcome and timing of these initiatives are uncertain.

There are six greenhouse gases. The Utility and PG&E NEG emit varying quantities of these greenhouse gases, including carbon dioxide and methane, in the course of their operations. Depending on the ultimate regulatory regime put into place for greenhouse gases, the Utility's or PG&E NEG's operations, cash flows and financial condition could be adversely affected. Given the uncertainty of the regulatory regime, it is not possible to predict the extent to which climate change regulation will have a material adverse effect on the Utility's or PG&E NEG's financial condition or result of operations.

The Utility and PG&E NEG are taking numerous steps to manage the potential risks associated with the eventual regulation of greenhouse gases, including but not limited to preparing inventories of greenhouse gas emissions, voluntarily reporting on these emissions through a variety of state and federal programs, engaging in demand side management programs that prevent greenhouse gas emissions, and supporting market-based solutions to the climate change challenge.

Recorded Liability for Legal Matters

In accordance with SFAS No. 5, "Accounting for Contingencies," PG&E Corporation makes 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 $219 million at June 30, 2003, and $202 million at December 31, 2002.

Legal Matters

In the normal course of business, PG&E Corporation, the Utility, and PG&E NEG 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.

The Utility has filed 13 summary judgment motions challenging the claims of the trial test plaintiffs and four of the 13 summary judgment motions are scheduled for hearing in 2003. At a status conference on March 17, 2003, the Los Angeles Superior Court scheduled a trial of 18 test cases to commence in March 2004.

The Utility has recorded a reserve in its financial statements in the amount of $160 million for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at June 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 and PG&E GTN. 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, acting through the 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 U.S. 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 Indian 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.

Federal Securities Lawsuit

This matter involves a second amended complaint that was filed against PG&E Corporation and an executive officer of PG&E Corporation on February 4, 2002, in the U.S. District Court for the Northern District of California, purportedly brought on behalf of all persons who purchased PG&E Corporation common stock or certain shares of the Utility's preferred stock between July 20, 2000, and April 9, 2001. In January 2002, the District Court dismissed the plaintiffs' first amended complaint. The first and second amended complaints alleged that the defendants caused PG&E Corporation's Consolidated Financial Statements for the second and third quarters of 2000 to be materially misleading in violation of federal securities laws as a result of recording as a deferred cost and capitalizing as a regulatory asset the under-collections that resulted when escalating wholesale energy prices caused the Utility to pay far more to purchase electricity than it was permitted to collect fro m customers. In the second amended complaint, the plaintiffs also repeated some of the allegations that appear in the California Attorney General's complaint discussed below. The plaintiffs sought an unspecified amount of compensatory damages, plus costs and attorneys' fees. In dismissing the first amended complaint, the District Court found that the complaint failed to state a claim in light of the public disclosures by PG&E Corporation, the Utility, and others regarding the under-collections, the risk that they might not be recoverable, the financial consequences of non-recovery, and other information from which analysts and investors could assess for themselves the probability of recovery.

In June 2002, the District Court dismissed the second amended complaint with prejudice, prohibiting the plaintiffs from filing a further complaint. The plaintiffs' appeal of the dismissal was argued before the U.S. Court of Appeals for the Ninth Circuit on June 10, 2003. In July 2003, the Ninth Circuit court upheld the District Court's dismissal of the plaintiffs' second amended complaint. The plaintiffs have until October 29, 2003 to file a petition asking the U.S. Supreme Court to hear their appeal of the Ninth Circuit's July 2003 decision.

PG&E Corporation believes the allegations to be without merit and will continue vigorously responding to and defending against the litigation. PG&E Corporation believes that the ultimate outcome of the litigation will not have a material adverse effect on its financial condition or results of operations.

Order Instituting Investigation (OII) into Holding Company Activities

On April 3, 2001, the CPUC issued an OII into whether the California IOUs, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. 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 holding company str ucture. 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 First Appellate District in San Francisco, California.

The proposed 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 settlement agreement is final and nonappealable, the Utility, 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 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.

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

On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against directors of the Utility, alleging that PG&E Corporation violated various conditions established by the CPUC in decisions approving the holding company formation, among other allegations. The Attorney General also alleged that the December 2000 and January and February 2001 ringfencing transactions by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions.

Among other allegations, the Attorney General alleged that, through the Utility's Chapter 11 proceedings, PG&E Corporation and the Utility engaged in unlawful, unfair, and fraudulent business practices in alleged violation of California Business and Professions Code Section 17200 by seeking to implement the transactions contemplated in the original proposed plan of reorganization filed in the Utility's Chapter 11 proceeding. The complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. In February 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the Attorney General's complaint to the Bankruptcy Court, as well as a motion to dismiss the lawsuit, or in the alternative, to stay the suit with the Bankruptcy Court. Subsequently, the Attorney General filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court held that federal law preempted the Attorney General's all egations concerning PG&E Corporation's participation in the Utility's Chapter 11 proceedings. The Bankruptcy Court directed the Attorney General to file an amended complaint omitting these allegations and remanded the amended complaint to the San Francisco Superior Court. Both parties appealed the Bankruptcy Court's remand order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are waiting for a decision.

On August 9, 2002, the California Attorney General filed its amended complaint in the San Francisco Superior Court, omitting the allegations concerning PG&E Corporation's participation in the Utility's Chapter 11 proceedings. A status conference has been scheduled for August 29, 2003.

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

After removing the City's action to the Bankruptcy Court in February 2002, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the Bankruptcy Court issued an Amended Order on Motion to Remand stating that the Bankruptcy Court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to state court. Both parties have appealed the Bankruptcy Court's remand order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are waiting for a decision. A status conference has been scheduled for August 29, 2003.

In addition, a third case, entitled Cynthia Behr v. PG&E Corporation, et al., was filed on February 14, 2002, by a private plaintiff (who also has filed a claim under Chapter 11) in Santa Clara Superior Court also alleging a violation of California Business and Professions Code Section 17200. The Behr complaint also names the directors of PG&E Corporation and the Utility as defendants. The allegations of the complaint are similar to the allegations contained in the Attorney General's complaint but also include allegations of conspiracy, fraudulent transfer, and violation of the California bulk sales laws. The plaintiff requests the same remedies as the Attorney General's case and in addition requests damages, attachment, and restraints upon the transfer of defendants' property. In March 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the complaint to the Bankruptcy Court. Subsequently, the plaintiff filed a motion to remand the action to state court. In its June 2002 ruling mentioned above as to the Attorney General's and the City's cases, the Bankruptcy Court retained jurisdiction over Behr's fraudulent transfer claim and bulk sales claim, finding them to belong to the Utility's estate. The Bankruptcy Court remanded Behr's Section 17200 claim to the Santa Clara Superior Court. Both parties have appealed the Bankruptcy Court's remand order to the Northern District. The appeal and cross-appeal were argued before the Northern District on July 24, 2003, and the parties are waiting for a decision.

In April 2003, the San Francisco Superior Court dismissed Behr's civil conspiracy cause of action. A status conference has been scheduled for August 29, 2003.

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

PG&E Corporation believes that the allegations of the complaints are without merit and will vigorously respond to and defend against the litigation. PG&E Corporation cannot predict whether the outcome of the litigation will have a material adverse effect on its 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 June 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 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.

Mitsubishi Litigation

On May 7, 2003, Mitsubishi Heavy Industries, Inc. (MHI) filed suit in the U.S. District Court for the District of Maryland against PG&E NEG, PG&E National Energy Group, LLC (NEG LLC) and PG&E National Energy Group Construction Company, LLC (NEG Construction), involving a turbine purchase agreement and related contracts. On or about July 21, 2003, PG&E NEG notified the District Court of the automatic stay of litigation imposed by the bankruptcy laws. In its complaint, MHI alleges damages totaling approximately $300 million under the turbine purchase agreement and related contracts. MHI's claims arise from a dispute between the parties to a turbine purchase agreement regarding payments allegedly past due from NEG Construction in respect of reservation fees ($9.5 million) and gas generator equipment manufacture ($30 million). MPS also requested that PG&E NEG cash collateralize its $75 million guarantee issued in connection with the turbine purchase agreement. PG&E NEG and NEG Con struction have maintained (and will maintain in defense of MHI's claims) that no amounts were or are due.

As a result of PG&E NEG's Chapter 11 filing, on August 5, 2003, the District Court entered an order staying the litigation. MHI has voluntarily dismissed, without prejudice, its claims against NEG LLC, and has opposed the District Court's stay order. NEG Construction intends to oppose MHI's response to the District Court's stay order.

The outcome of this matter is not expected to have a material adverse effect on PG&E Corporation's results of operations or financial condition. Effective July 8, 2003, PG&E NEG's results will no longer be consolidated into PG&E Corporation's financial results (see Note 1).

NOTE 7: SEGMENT INFORMATION

PG&E Corporation has identified three reportable operating segments based on similarities in the following characteristics:

• Economics;

• Products and services;

• Types of customers;

• Methods of distribution;

• Regulatory environment; and

• How information is reported to and used by PG&E Corporation's chief operating decision makers.

The Utility is one reportable operating segment and the other two are part of PG&E NEG. These three reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions.

Segment information for the three and six months ended June 30, 2003, and 2002, was as follows:

								PG&E National Energy Group
(in millions)					Utility			Total PG&E NEG		Integrated Energy & Marketing Activities			Interstate Pipeline Operations		PG&E NEG Elimi- nations		PG&E Corpora- tion, Elimi- nations and Other (1)		Total
Three months ended June 30, 2003
Operating revenues (6)				$		2,729		$	197	$	172		$	45	$	(20)	$	-	$	2,926
Intersegment revenues (2)				1				13		(1)			14		-		(14)		-
Total operating revenues				2,730				210		171			59		(20)		(14)		2,926
Income (Loss) from continuing operations(3)					339			(165)		(74)			13		(104)		45		219
Net income (loss)(4)				339				(155)		(65)			13		(103)		43		227
Three months ended June 30, 2002 (5)
Operating revenues (6)				2,711				226		187			44		(5)		-		2,937
Intersegment revenues (2)				3				19		9			10		-		(22)		-
Total operating revenues				2,714				245		196			54		(5)		(22)		2,937
Income (Loss) from continuing operations(3)					463			(180)		(190)			17		(7)		(4)		279
Net income (loss)(4)				463				(241)		(251)			17		(7)		(4)		218
Six months ended June 30, 2003
Operating revenues (6)				4,793				434		378			94		(38)		-		5,227
Intersegment revenues (2)				4				35		6			29		-		(39)		-
Total operating revenues				4,797				469		384			123		(38)		(39)		5,227
Income (Loss) from continuing operations(3)							261	(419)		(224)			29		(224)		99		(59)
Net income (loss)(4)				260				(524)		(282)			29		(271)		137		(127)
Six months ended June 30, 2002 (5)
Operating revenues (6)				5,161				449		367			91		(9)		-		5,610
Intersegment revenues (2)				6				50		28			22		-		(56)		-
Total operating revenues				5,167				499		395			113		(9)		(56)		5,610
Income (Loss) from continuing operations(3)			1,053					(150)		(171)			35		(14)		-		903
Net income (loss)(4)				1,053				(204)		(225)			35		(14)		-		849
Total assets at June 30, 2003(7)		$			26,013			$	6,810	$		6,629	$	1,329	$	(1,148)	$	1,685	$	34,508
Total assets at June 30, 2002(7)		$			24,648			$	11,422	$		9,953	$	1,355	$	114	$	709	$	36,779
(1)	Includes PG&E Corporation, PG&E Ventures LLC, and elimination entries. PG&E Corporation eliminated $54 million for the three-month and $160 million for the six-month periods ended June 30, 2003, of deferred tax asset valuation reserves recorded at PG&E NEG. 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)	Intersegment electric and gas revenues are recorded at market prices, except for the Utility, which uses rates set by the CPUC, and PG&E NEG's Interstate Pipeline Operations, which uses rates set by the FERC.
(3)	Corresponds to Utility's Income Available for Common Stock excluding Cumulative Effect of Changes in Accounting Principles.
(4)	Corresponds to Utility's Income Available for Common Stock.
(5)	Prior period amounts have been restated to reflect the reclassification of USGenNE, Mountain View, ET Canada, and Ohio Peakers operating results and net gains on disposal to discontinued operations.
(6)	Operating revenues and operating expenses reflect the adoption of a new accounting policy in the third quarter of 2002 implementing a retroactive change from gross to net method of reporting revenues and expenses on trading activities and the netting of certain revenues and expenses, primarily related to hedging activities in the second quarter of 2003. The amounts for trading and these certain hedging activities for prior periods have been reclassified to conform with the new net presentation.
(7)	PG&E Corporation's assets exclude its investment in subsidiaries.

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. The Utility's defined benefit pension plan currently exceeds the minimum funding requirements of the Employee Retirement Income Security Act of 1974.

NOTE 9: SUBSEQUENT EVENTS

On July 2, 2003, PG&E Corporation completed a private placement of $600 million of 6-7/8 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 and are senior to all existing and future subordinated indebtedness, including PG&E Corporation's outstanding $280 million 9.50 percent Convertible Subordinated Notes.

The indenture, dated as of July 2, 2003, does not contain restrictions on the ability of the Utility and PG&E NEG to incur debt.

The net proceeds of the offering of approximately $583 million, together with cash on hand, were used to repay approximately $739 million under PG&E Corporation's existing credit agreement. A pre-tax loss of approximately $89 million will be recorded in the third quarter of 2003 to reflect the write-off to interest expense of unamortized loan fees, loan discount and prepayment fees. 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 PG&E NEG, as well as the prior lien on approximately 94 percent of the outstanding common stock of the Utility.

Interest on the Notes accrues at the rate of 6-7/8 percent per annum and is payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2004. The notes are redeemable at the option of PG&E Corporation at any time, at redemption prices described in the indenture. PG&E Corporation is not required to make mandatory redemption or sinking fund payments with respect to the Notes. However, under certain circumstances involving a change of control, spin-off, or reorganization event, as described in the indenture, PG&E Corporation is required to offer to purchase the Notes.

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

OVERVIEW

PG&E Corporation is a holding company headquartered in San Francisco, California: its principal subsidiary, the 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 causing 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 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 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 they are subject to the jurisdiction of the Bankruptcy Court. The factors causing PG&E NEG to take this action are discussed in this MD&A and in Note 3 of the Notes to the Consolidated Financial Statements.

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 Chapter 11 filings of both the Utility and PG&E NEG and certain of its subsidiaries, as further discussed below, such realization of assets and liquidation of liabilities are subject to uncertainty.

PG&E Corporation has identified three reportable operating segments:

• Utility;

• Integrated Energy and Marketing, or the Generation Business; and

• Interstate Pipeline Operations, or the Pipeline Business.

These segments were determined based on similarities in the following characteristics:

• Economic;

• Products and services;

• Types of customers;

• Methods of distribution;

• Regulatory environment; and

• How information is reported to and used by PG&E Corporation's chief operating decision makers.

These three reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdiction. Financial information about each reportable operating segment is provided in this MD&A and in Note 7 of the Notes to the Consolidated Financial Statements.

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

• How related commitments and contingencies 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, PG&E NEG, 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 changes that may be made to reflect changes in the California Department of Water Resources' (DWR) revenue requirements;

• 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;

• The effect of judicial decisions on the CPUC's authority to enter into and perform its obligations under the proposed settlement agreement, including the California Supreme Court's consideration of the legality of recovery of under-collected costs by another California utility, Southern California Edison Company (SCE), under a settlement and stipulated federal court judgment with the CPUC;

• 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 and other natural phenomena;

• 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 demand for and pricing of natural gas transportation and storage services, which may be affected by weather, overall gas-fired generation, and price spreads between various natural gas delivery points;

• The inability of various counterparties to meet their obligations under their power sale agreements with the Utility or with the DWR thereby increasing the Utility's risk to procure additional power to cover the net open position;

• The Utility's ability to manage the net open position over time;

• 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;

• Storms, earthquakes, fires, explosions, accidents, mechanical breakdowns and other events or perils that result in power outages or damage to the Utility's assets or operations, to the extent not covered by insurance;

• 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 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 conditions;

• 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 expense; and

• The effect of compliance with existing and future environmental laws, regulations and policies.

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 the 2003 General Rate Case (GRC) and proceedings to determine the allocable amount of DWR revenue requirements and the method of remittance of pass-through revenues collected by the Utility to the DWR.

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

• 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; and

• Changes in vendor relationships.

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.

PG&E NEG Chapter 11 Proceedings. PG&E Corporation's future results of operations and financial condition may be affected by whether PG&E Corporation is determined to be liable for any claims asserted by PG&E NEG or its creditors in PG&E NEG's Chapter 11 proceedings and the amount of any claims for which PG&E Corporation is determined to be liable.

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 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, 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

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 a competing 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.

The Proposed 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 settlement agreement, PG&E Corporation and the Utility would agree that they no longer would propose to disaggregate the historic businesses of the Utility as had been proposed in the original plan of reorganization. Instead, the Utility would remain a vertically integrated utility subject to the CPUC's jurisdiction.

The treatment of creditors under the Settlement Plan would be consistent with that provided in the Utility's original plan of reorganization, except that those creditors that were to receive long-term notes to be issued by the limited liability companies contemplated under the original plan of reorganization or a combination of cash and long-term notes would be paid entirely in cash. The Settlement Plan contemplates satisfaction of allowed claims in the Utility's Chapter 11 proceeding in cash from the issuance of approximately $8.7 billion in debt (which may be either secured or unsecured depending on market conditions at the time of issuance), cash on hand, or, in some cases, the reinstatement of the underlying debt. 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 re instated debt will be reinstated.

The proposed 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 settlement agreement must be executed by all parties on or before December 31, 2003. The CPUC will conduct evidentiary hearings during September 2003 before deciding whether or not to approve the proposed settlement agreement. On July 25, 2003, the Utility filed its testimony in support of the proposed settlement agreement. Testimony from the staff of the CPUC and the OCC were also filed on July 25, 2003. The CPUC currently is expected to vote on the settlement agreement on December 18, 2003.

In addition, the Bankruptcy Court must confirm the Settlement Plan. While the CPUC is not a proponent, it would agree under the proposed settlement agreement to support the Settlement Plan. On July 31, 2003, the Bankruptcy Court approved the disclosure statement that will be used to solicit approval of the Settlement Plan from creditors entitled to vote on the Settlement Plan. On August 1, 2003, the Bankruptcy Court approved the solicitation procedures and ordered that the solicitation period to start on August 15 and end on September 29, 2003. The Bankruptcy Court has ordered that the confirmation hearing begin on November 3, 2003, and that all objections to the Settlement Plan be filed by September 2, 2003.

Regulatory Assets

The proposed settlement agreement provides for a new regulatory asset (Regulatory Asset) to restore the Utility to financial health and to maintain and improve the Utility's financial health in the future. The Regulatory Asset would be a separate and additional part of the Utility's rate base of approximately $3.7 billion, pre-tax, included in non-current assets on the Utility's balance sheet. The Regulatory Asset would be amortized on a mortgage-style basis over nine years beginning January 1, 2004.

The Utility would continue to cooperate with the CPUC and the State of California in seeking refunds from power generators. The net after-tax amount of any refunds, claim offsets, or other credits from generators or other energy suppliers relating to the Utility's power procurement costs that the Utility actually realizes in cash or by offset of creditor claims in its Chapter 11 proceeding would be applied to reduce the outstanding balance and the remaining amortization of the Regulatory Asset. Amounts received in cash by the Utility for electric claims under the master settlement agreement with El Paso Corporation and certain of its affiliates (El Paso) also would be included in such a reduction.

The Regulatory Asset would earn a return on equity (ROE) of at least 11.22 percent for the life of the Regulatory Asset. For 2004 and 2005, the common equity ratio of the Utility's capital structure would be the higher of forecast average equity ratio (in accordance with the 2003 cost of capital proceedings to be filed by the Utility for calendar year 2004 and the 2005 cost of capital proceeding, or such other CPUC proceedings as may be appropriate) or 48.60 percent. Once the common equity ratio of the Utility's capital structure reaches 52.00 percent, the authorized common equity ratio of the Regulatory Asset would be no less than 52.00 percent for the remaining life of the Regulatory Asset. The CPUC would use its usual method for tax-effecting the ROE component of the Regulatory Asset in establishing the Utility's revenue requirements for the Regulatory Asset. The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

The CPUC would agree that the Utility's rate base for its 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 regulatory asset of approximately $1.3 billion, pre-tax, for the future recovery of generation-related assets that were charged to expense in 2000. The CPUC would not be precluded from determining the reasonableness of any capital expenditures made for URG after the effective date of the Settlement Plan. The Utility would record this regulatory asset when events that meet applicable accounting rules occur.

The CPUC would not reduce or impair the value of the Regulatory Asset or the Utility's rate base for its URG, by taking the Regulatory Asset or the Utility's rate base for its URG, or their amortization or earnings into account when setting other Utility revenue requirements and resulting rates. The CPUC also would not take the settlement agreement or the Regulatory Asset into account in establishing the Utility's authorized ROE or capital structure.

Among other terms, the proposed settlement agreement also provides that:

Ratemaking Matters

• The CPUC would maintain the Utility's retail electric rates at current levels through December 31, 2003. Beginning January 1, 2004, the CPUC may adjust the Utility's retail electric rates prospectively consistent with the proposed settlement agreement, the Settlement Plan, the order confirming the Settlement Plan, and California law. The proposed settlement agreement contemplates that retail electric 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, provided that, from January 1, 2004, until Standard & Poor's (S&P) has issued a long-term issuer credit rating for the Utility of at least A- or Moody's Investors Services (Moody's) has issued an issuer 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 forecast average equity ratio in the Utility's cost of capital proceeding or 48.60 percent.

• Balances in the Utility's Transition Cost Balancing Account (which tracks the amount of the Utility's under-collected transition and electricity procurement costs) as of the effective date of the Settlement Plan would have no further impact on the Utility's retail electric rates and would not be subject to further CPUC review except for verification of recorded balances.

• 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 California legislation (Assembly Bill (AB) 57 and Senate Bill (SB) 1976) and the CPUC-DWR rate agreement 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 URG, 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 previously incurred costs of providing electric service from ratepayers under the federal filed rate d octrine, the settlement agreement, the Regulatory Asset, or any other matters addressed or resolved by the proposed settlement agreement.

• The Utility would file an advice letter to implement all of the rate and tariff changes necessary to implement the Settlement Plan. The CPUC would act promptly on the advice filing and revised rates and tariffs. The CPUC also would 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 Sheet.

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 (1) the Utility receives a long-term issuer credit rating of at least A from S&P and A2 from Moody's, after giving effect to such assignment or assumption, (2) the CPUC first has made a finding that the DWR contracts being assumed are just and reasonable, and (3) the CPUC has acted to ensure that the Utility receives full and timely rate recovery of all costs of the DWR contracts over their lives without further review. The CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law.

Headroom Revenues - 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 settlement defines headroom as the Utility's total net after-tax income reported under accounting principles generally accepted in the United States of America (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 200 3 GRC. The proposed 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 settlement agreement provides that if headroom revenues accrued by the Utility during 2003 are greater than $875 million, pre-tax, the Utility would refund the excess to ratepayers. Further, if headroom revenues are less than $775 million, pre-tax, the CPUC would allow the Utility to collect the shortfall in rates. Headroom revenues for the six months ended June 30, 2003, were $237 million, pre-tax, as calculated under the terms of the proposed settlement agreement.

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 no longer is subject to appeal, the Utility would dismiss with prejudice its "filed rate case" and withdraw the original plan of reorganization. In addition, the CPUC would 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.

Fees and Expenses - The proposed settlement agreement would require the Utility to reimburse PG&E Corporation and the CPUC, after the date the Settlement Plan is confirmed, for all of their respective professional fees and expenses incurred in connection with the Chapter 11 proceeding. Of such amounts, the amounts reimbursed to the CPUC could be recovered from ratepayers. As of June 30, 2003, PG&E Corporation has incurred expenses of approximately $121 million on the Utility's Chapter 11 proceeding.

Environmental Measures - The Utility would implement three environmental enhancement measures:

• The Utility would encumber with conservation easements or donate approximately 140,000 acres of specific watershed and other 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 such corporation over ten years with $70 million, although it would be entitled to recover these payments in rates without further review; and

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

Term - The proposed settlement agreement generally would terminate nine years after the effective date of the Settlement Plan, except that all vested rights of the parties under the proposed settlement agreement would survive termination for the purpose of enforcement.

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 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 deemed 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 notes 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 notes to be offered by the Utility of not less than BBB- and Baa3, respectively;

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

• Each of the parties to the proposed settlement agreement have 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 the proposed 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 settlement agreement and related rates, or if the CPUC takes actions materially inconsistent with the proposed 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 of the Notes to the Consolidated Financial Statements, then the Utility's financial condition and results of operations could be materially adversely affected. The settlement agreement and Settlement Plan may also be affected by the outcome of the California Supreme Court's consideration of questions certified to it by the Ninth Circuit regarding the validity of the settlement agreement between the CPUC and SCE. Several entities, including The Utility Reform Network (TURN) challenged the SCE settlement. Oral argument occurred before the California Supreme Court on May 27, 2003, and it is expected that the Court will issue a ruling by August 27, 2003. The Utility believes that, even if the California Supreme Court finds the SCE settlement violates state law, there are independent legal and factual reasons under which the proposed settlement agreement and the Settlement Plan would still be valid under state and federal law. The effectiveness of the Settlement Plan is not conditioned upon receiving a favorable ruling in the SCE case by the California Supreme Court.

PG&E NEG

As of June 30, 2003, PG&E NEG and certain of its subsidiaries are in default under various debt agreements and guaranteed equity commitments totaling approximately $5.6 billion of which approximately $2.8 billion is non-recourse to PG&E NEG. As a consequence of these defaults, and in spite of efforts to structure an agreement that would allow PG&E Corporation to retain ownership of PG&E NEG, on July 8, 2003, PG&E NEG filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code. In addition, on July 8, 2003, each of the following indirect wholly owned subsidiaries of PG&E NEG filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code in the Bankruptcy Court: PG&E ET Investments Corporation; PG&E Energy Trading Holdings Corporation; PG&E Energy Trading - Power, L.P.; and PG&E Energy Trading - Gas Corporation (collectively, the "ET Companies"); and, separately, USGen New England, Inc. (USGenN E). On July 29, 2003, two other subsidiaries, Quantum Ventures and 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 PG&E NEG and the other subsidiaries.

Pursuant to Chapter 11 of the Bankruptcy Code, PG&E NEG, 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, PG&E NEG 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. PG&E NEG's proposed plan of reorganization would not restructure the indebtedness of any of the debtors, other than PG&E NEG. If PG&E NEG's plan of reorganization is confirmed by the Bankruptcy Court and implemented, PG&E Corporation no longer would have any equity interest in PG&E NEG or any of its subsidiaries. It is anticipated that the Chapter 11 plans for USGenNE and the ET Companies will b e filed at a later date.

The accompanying PG&E Corporation Consolidated Financial Statements include the consolidated results of PG&E NEG though June 30, 2003. As a result of PG&E NEG's Chapter 11 filing and the resignation of PG&E Corporation's representatives who previously served on the PG&E NEG 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 PG&E NEG. Accordingly, effective July 8, 2003, PG&E Corporation no longer will consolidate PG&E NEG's financial results and will begin accounting for its investment in PG&E NEG using the cost method. In accordance with the cost method, PG&E Corporation no longer will recognize its equity share in the income or losses of PG&E NEG and will record its investment in and advances to PG&E NEG as a non-current liability on the Consolidated Balance Sheets (see the accompanyin g pro forma consolidated financial information). This investment will not be affected by changes in PG&E NEG's future financial results, other than (1) investments in or dividends from PG&E NEG, or (2) income taxes PG&E Corporation may be required to pay if the Interal Revenue Service disallows certain deductions or tax credits attributable to PG&E NEG and its subsidiaries for past tax years and incorporated into PG&E Corporation's consolidated tax returns.

Upon implementation of PG&E NEG's plan of reorganization that eliminates PG&E Corporation's equity in PG&E NEG, PG&E Corporation would bring its investment in PG&E NEG to zero and, as a result, recognize a one-time non-cash gain to earnings. The amount of such potential gain cannot be estimated at this time.

Summary Pro Forma Consolidated Financial Information

The following summary of pro forma consolidated financial information for PG&E Corporation gives effect to the change of accounting for PG&E NEG from consolidated financial reporting to the cost method of accounting.

The Pro Forma Consolidated Statements of Operations and Balance Sheet of PG&E Corporation are presented as if PG&E Corporation had never consolidated PG&E NEG for financial reporting purposes. This financial information should be read in conjunction with the historical financial statements and related notes of PG&E Corporation, which are included in the combined PG&E Corporation and Utility 2002 Annual Report on Form 10-K, as amended. The Pro Forma Consolidated Balance Sheet at June 30, 2003, assumes that PG&E NEG had been deconsolidated on that date. The Pro Forma Consolidated Statements of Operations for the six months ended June 30, 2003, and the year ended December 31, 2002, assume that PG&E NEG had been deconsolidated on January 1, 2002, the beginning of the earliest fiscal period presented.

This summarized pro forma financial information does not include any anticipated future financial impacts that may occur from PG&E NEG's Chapter 11 filing, or from implementing its plan of reorganization. Also, the summarized pro forma financial information does not necessarily indicate what PG&E Corporation's financial position or operating results would have been if PG&E NEG had filed for Chapter 11 before the periods presented, and does not necessarily indicate future operating results of PG&E Corporation with or without PG&E NEG.

PG&E CORPORATION

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

(in millions, except per share amounts)

			Pro Forma Adjustments to Apply Cost Accounting for PG&E NEG (c)
	As Reported Six months ended June 30, 2003 (a)		Deconsolidate PG&E NEG (b)		Eliminations and Other		Pro Forma Six months ended June 30, 2003
Total Operating Revenues	$	5,227	$	(469)	$	39	$	4,797
Total Operating Expenses		4,653		(712)		39	3,980
Operating Income		574		243		-	817
Interest Expense, Net and Other		(697)		215		-	(482)
Income Taxes (Benefit)		(64)		39		(39)	(64)
Income (Loss) from Continuing   Operations (e)	$	(59)	$	419	$	39	$	399
Weighted Average Common Shares   Outstanding, Basic		383						383
Earnings (Loss) Per Common Share,   from Continuing Operations, Basic	$	(0.15)					$	1.04
Weighted Average Common Shares   Outstanding, Diluted		383						408
Earnings (Loss) Per Common Share,   from Continuing Operations, Diluted	$	(0.15)					$	1.00

PG&E CORPORATION

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

(in millions, except per share amounts)

			Pro Forma Adjustments to Apply Cost Accounting for PG&E NEG (c)
	As Reported Year ended December 31, 2002 (a)		Deconsolidate PG&E NEG (b)		Eliminations and Other				Pro Forma Year ended December 31, 2002
Total Operating Revenues	$	12,495	$	(2,075)	$		94			$		10,514
Total Operating Expenses		11,363		(4,812)			94			6,645
Operating Income		1,132		2,737			-			3,869
Interest Expense, Net and Other		(1,232)		144			-			(1,088)
Income Taxes (Benefit)		(43)		656			(381)			232
Income (Loss) from Continuing   Operations (e)	$	(57)	$	2,225	$	381		$			2,549
Weighted Average Common Shares   Outstanding, Basic		371									371
Earnings (Loss) Per Common Share,   from Continuing Operations, Basic	$	(0.15)						$			6.87
Weighted Average Common Shares   Outstanding, Diluted		371									384
Earnings (Loss) Per Common Share,   from Continuing Operations, Diluted	$	(0.15)						$			6.66

PG&E CORPORATION

PRO FORMA CONSOLIDATED BALANCE SHEET

(in millions)

			Pro Forma Adjustments to Apply Cost Accounting for PG&E NEG (d)
	As Reported Balance at June 30, 2003 (a)		Deconsolidate PG&E NEG (b)		Eliminations and Other		Pro Forma Balance at June 30, 2003
Assets
Current Assets (e)	$	9,343	$	(2,087)	$	31	$	7,287
Net Property, Plant and Equipment		18,972		(3,052)		-		15,920
Other Assets (e)		6,193		(1,671)		(11)		4,511
Total Assets	$	34,508	$	(6,810)	$	20	$	27,718
Liabilities and Equity
Debt in Default	$	4,691	$	(4,691)	$	-	$	-
Current Portion of Long-Term Debt		602		(11)		-		591
Current Portion of Rate Reduction Bonds		290		-		-		290
Other Current Liabilities (e)		3,607		(1,546)		67		2,128
Long-Term Debt		4,034		(611)		-		3,423
Rate Reduction Bonds		1,019		-		-		1,019
Loss in Excess of Investment in PG&E NEG		-		-		1,104		1,104
Other Non-Current Liabilities (e)		7,015		(1,487)		315		5,843
Liabilities Subject to Compromise		9,273		-		4		9,277
Preferred Stock of Subsidiaries		480		(58)		-		422
Common Shareholders' Equity		3,497		1,594		(1,470)		3,621
Total Liabilities and Equity	$	34,508	$	(6,810)	$	20	$	27,718

(a)	"As Reported" Consolidated Statement of Operations amounts for the year ended December 31, 2002, were derived from the audited Consolidated Financial Statements included in PG&E Corporation's 2002 Annual Report on Form 10-K, as amended. "As Reported" Consolidated Statement of Operations amounts for the six months ended June 30, 2003, and Consolidated Balance Sheet amounts at June 30, 2003, were derived from the unaudited Condensed Consolidated Financial Statements included in this PG&E Corporation Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003. Certain amounts in the 2002 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation. "As Reported" Consolidated Statement of Operations amounts reflect PG&E Corporation's elimination of deferred tax asset valuation reserves recorded at PG&E NEG of $160 million for the six months ended June 30, 2003, and $762 million for the year ended December 31, 2002. "As Reported" Consolidated Balance Sheet amounts include deferred tax assets of $605 million related to PG&E NEG at June 30, 2003. PG&E Corporation continues to believe it is more likely than not that it will be able to realize these deferred tax assets for income tax purposes, and as such, the pro forma amounts also reflect the utilization of these tax benefits.
(b)	"PG&E NEG" Consolidated Statement of Operations amounts for the year ended December 31, 2002, were derived from the audited Consolidated Financial Statements of PG&E NEG. "PG&E NEG" Consolidated Statement of Operations amounts for the six months ended June 30, 2003, and Consolidated Balance Sheet amounts at June 30, 2003, were derived from the unaudited condensed Consolidated Financial Statements of PG&E NEG.
(c)	Pro forma adjustments in the Consolidated Statement of Operations reflect (1) the elimination of PG&E NEG's financial results from PG&E Corporation's Consolidated Financial Statements, (2) elimination of inter-segment operating and non-operating revenues and expenses, (3) reclassification of PG&E NEG's federal deferred tax assets from Discontinued Operations and Cumulative Effect of Changes in Accounting Principles to Income Taxes (Benefit) for Continuing Operations, and (4) conforming reclassification adjustments in presentation between PG&E NEG and PG&E Corporation's financial information.
(d)	Pro forma adjustments in the Consolidated Balance Sheet reflect (1) the elimination of PG&E NEG's assets, liabilities, preferred stock, and accumulated other comprehensive loss from PG&E Corporation's Consolidated Financial Statements, (2) elimination of inter-segment receivables and payables, (3) reinstatement of the Utility's inter-segment balances with PG&E NEG, which were previously eliminated under the consolidated method of reporting PG&E NEG, (4) cost accounting adjustments to reflect PG&E Corporation's net investment in PG&E NEG as a single line item within non-current liabilities on its Consolidated Balance Sheet (Loss in Excess of Investment in PG&E NEG), (5) netting of PG&E Corporation's receivable from PG&E NEG to net investment in PG&E NEG (Loss in Excess of Investment in PG&E NEG), and (6) conforming reclassification adjustments in presentation between PG&E NEG and PG&E Corporation's financial information.
(e)	Pro forma adjustments referred to in (c) and (d) above include the elimination of PG&E NEG's projects and operations that were sold in 2002 or 2003, or were considered held for sale in those periods. Under the cost method of accounting presented here on a pro forma basis, the operating results of these PG&E NEG projects and operations are no longer presented as Discontinued Operations, and the related assets and liabilities are no longer presented as Assets and Liabilities Held for Sale. This reclassification has increased Income from Continuing Operations for the amounts previously reported as Discontinued Operations.

PG&E Corporation has reduced the discussion of PG&E NEG's liquidity and financial resources and its results of operations from that contained in the annual and quarterly reports. For a discussion of these matters related to PG&E NEG, refer to PG&E NEG's Securities and Exchange Commission (SEC) filings.

COMMITMENTS AND CAPITAL EXPENDITURES

The Utility and PG&E NEG have substantial financial commitments in connection with operating, construction, and development activities.

Utility

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 loan 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 commitments of the Utility.

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

PG&E NEG

As discussed above, as a result of PG&E NEG's Chapter 11 filing, it is expected that PG&E NEG's commitments and capital expenditures no longer will have any material financial impact on PG&E Corporation's commitments or future financial condition.

CASH FLOWS

Utility

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

Operating Activities

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

	Six months ended June 30,
(in millions)	2003		2002
Net income	$	272	$	1,065
Non-cash (income) expenses:
Depreciation, amortization, and decommissioning	605		565
Interest	103		264
Income tax	152		370
Net reversal of ISO accrual and DWR revenue requirement adjustment	-		(595)
Other uses of cash:
Payments authorized by the Bankruptcy Court on amounts classified as     liabilities subject to compromise	(62)		(947)
Other changes in operating assets and liabilities	134		(92)
Net cash provided by operating activities	$	1,204	$	630

Net cash provided by operating activities increased by $574 million during the six months ended June 30, 2003, in comparison to the same period in 2002. This increase was primarily due to the following:

• Net income decreased by $793 million due primarily to lower average electric sales prices, an increase in electric revenues passed through to the DWR and an increase in the cost of electricity. See discussion of factors impacting the Utility's net income in the " Results of Operations" section of this MD&A. Net income for the six months ended June 30, 2003, included net non-cash depreciation, interest, and income tax expenses totaling $860 million. Net income in the six months ended June 30, 2002, included net non-cash expenses totaling $604 million including $1,199 million in non-cash depreciation, interest and income tax expenses and a net $595 million reduction to cost of electricity in the six months ended June 30, 2002, related to the reversal of accrued Independent System Operator (ISO) charges and the adjustment of the DWR's 2001 revenue requirement.

• Payments on amounts classified as liabilities subject to compromise decreased by $885 million in the six months ended June 30, 2003, in comparison to the same period in 2002, due to significant pre-petition amounts paid to QFs in the six months ended June 30, 2002, based on Bankruptcy Court-approved settlements.

Investing Activities

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

	Six months ended June 30,
(in millions)	2003		2002
Capital expenditures	$	(730)	$	(743)
Net proceeds from sale of assets	11		5
Other investing activities	13		13
Net cash used by investing activities	$	(706)	$	(725)

Net cash used by investing activities decreased by $19 million during the six months ended June 30, 2003, in comparison to the same period in 2002. The decrease is attributable to a decrease in capital expenditures and an increase in proceeds from the sale of assets during the six months ended June 30, 2003.

Financing Activities

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

	Six months ended June 30,
(in millions)	2003		2002
Long-term debt issued, matured, redeemed, or repurchased	$	-	$	(333)
Rate reduction bonds matured	(141)		(141)
Other financing activities	-		(1)
Net cash used by financing activities	$	(141)	$	(475)

Net cash used by financing activities decreased by $334 million during the six months ended June 30, 2003, in comparison to the same period in 2002. The decrease is mainly due to $333 million in principal repaid on mortgage bonds in the six months ended June 30, 2002, with no such repayment in the six months ended June 30, 2003. Except as contemplated in the settlement plan, the Utility does not intend to seek external financing.

PG&E NEG

PG&E NEG's cash flows from operations for the six months ended June 30, 2003 and 2002 are not indicative of the future cash flows from operations due to the changes in the operations of PG&E NEG discussed above. As a result of PG&E NEG's Chapter 11 filing, it is expected that the future cash flows of PG&E NEG no longer will have any material financial impact on PG&E Corporation's cash flows.

Operating Activities

PG&E NEG's cash flows from operating activities for the six months ended June 30, 2003 and 2002 were as follows:

	Six months ended June 30,
(in millions)	2003		2002
Net loss	$	(524)	$	(204)
Adjustments to reconcile net loss to net cash     provided by operating activities	271		224
Price risk management assets and liabilities, net	(30)		67
Net effect of changes in operating assets and liabilities:
Restricted cash	(9)		(111)
Net, accounts receivable, accounts payable and accrued liabilities	96		103
Inventories, prepaids, deposits and other	304		(43)
Net cash provided by operating activities	$	108	$	36

Net cash provided by operating activities increased $72 million during the six months ended June 30, 2003, in comparison to the same period in 2002. This increase was primarily due to a decrease in restricted cash requirements of $102 million related to requirements of ongoing construction projects, as well as a decrease in working capital, including accounts receivable, inventories, prepaid expenses, deposits, and other liabilities of $347 million, as a result of the wind down of PG&E NEG's trading business. This increase was partly offset by a decrease in net price risk management (PRM) assets and liabilities of $97 million, due to realized losses from price changes and trade terminations and a $320 million increase in net loss.

Investing Activities

PG&E NEG's cash outflows from investing activities for the six months ended June 30, 2003 and 2002 will not be indicative of the future cash outflows from investing activities due to the changes in the operations of PG&E NEG discussed above.

PG&E NEG's cash outflows from investing activities for the six months ended June 30, 2003 and 2002 were as follows:

	Six months ended June 30,
(in millions)	2003		2002
Capital expenditures	$	(180)		$	(937)
Proceeds from sale leaseback	-		340
Net proceeds from disposal of discontinued operations	102		-
Other, net	33		104
Net cash used by investing activities	$	(45)		$	(493)

Net cash used by investing activities decreased $448 million during the six months ended June 30, 2003, in comparison to the same period in 2002. The decrease in cash used in investing activities was primarily due to reduced construction activities. Capital expenditures related to construction work in progress decreased by $728 million during the six months ended June 30, 2003, in comparison to the same period in 2002, as a result of the liquidity constraints of PG&E NEG discussed above. PG&E NEG received $102 million in proceeds on the sale of Mountain View during the first quarter of 2003 with no comparable event occurring during the first six months of 2002. In addition, PG&E NEG received $340 million of proceeds related to the Attala Generating Company, LLC (Attala Generating) sale leaseback transaction and $75 million in loan repayments between PG&E Corporation and PG&E GTN, both occurring in the second quarter 2002 with no comparable events during the first six months of 2003.

Included in investing activities for the six months ended June 30, 2003, are cash flows of $33 million and $42 million for the same period in 2002, related to the long-term receivable from New England Power Company associated with the assumption of power purchase agreements. These cash flows offset cash payments made to New England Power Company which are reflected in operating activities.

Financing Activities

PG&E NEG's cash flows from financing activities for the six months ended June 30, 2003 and 2002 were as follows:

	Six months ended June 30,
(in millions)	2003		2002
Net borrowings under debt in default	$	224	$	-
Repayment of obligations due related parties and affiliates	-		(100)
Long-term debt issued	9		952
Long-term debt matured, redeemed, or repurchased	(34)		(299)
Deferred financing costs	-		(37)
Net cash provided by financing activities	$	199	$	516

Net cash provided by financing activities decreased by $317 million during the six months ended June 30, 2003, in comparison to the same period in 2002. The decrease in cash provided from financing activities was primarily due to the prior year increase in nonrecourse long-term debt issued in connection with ongoing PG&E NEG construction projects.

PG&E Corporation

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

Operating Activities

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

	Six months ended June 30,
(in millions)	2003		2002
Net income (loss)	$	(127)	$	849
Adjustments ot reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	649		656
Net effect of changes in operating assets and liabilities:
Restricted cash	(207)		-
Accounts receivable	633		(55)
Accounts payable	(280)		335
Payments authorized by the Bankruptcy Court on amounts classified as       liabilities subject to compromise	(62)		(947)
Assets and liabilities of operations held for sale	(4)		18
Other, net	1,007		(444)
Net cash provided by operating activities	$	1,609	$	412

Net cash provided by operating activities increased by $1,197 million, during the six months ended June 30, 2003, in comparison to the same period in 2002. In addition to the specific effects of the Utility and PG&E NEG cash flow items discussed above, the increase is due to the following factors affecting PG&E Corporation:

• Return of excess tax payments of $533 million in May 2003, of which approximately $361 million was attributable to losses and deductions related to PG&E NEG and its subsidiaries in 2002. The amount attributable to losses and deductions related to PG&E NEG and its subsidiaries is not available for use or other disposition until resolution in PG&E NEG's Chapter 11 proceeding and is accordingly treated as restricted cash in the table above (see Note 6 of the Notes to the Consolidated Financial Statements); and

• Release of restricted cash of $246 million from escrow in January 2003.

Investing Activities

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

	Six months ended June 30,
(in millions)	2003		2002
Capital expenditures	$	(910)	$	(1,680)
Net proceeds from disposal of discontinued operations	102		-
Net proceeds from sale of assets	11		-
Proceeds from sale-lease back	-		340
Other, net	45		122
Net cash used by investing activities	$	(752)	$	(1,218)

Net cash used by investing activities decreased by $466 million, during the six months ended June 30, 2003, in comparison to the same period in 2002. The decrease is primarily due to PG&E NEG's reduced construction activities. In addition, PG&E NEG received proceeds from the sale of Mountain View during the six months ended June 30, 2003, with no comparable event occurring in the six months ended June 30, 2002.

Financing Activities

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

	Six months ended June 30,
(in millions)	2003		2002
Net borrowings under debt in default	$	224	$	-
Long-term debt issued	9		1,560
Long-term debt matured, redeemed, or repurchased	(34)		(1,081)
Rate reduction bonds matured	(141)		-
Common stock issued	54		61
Other, net	-		(37)
Net cash provided by financing activities	$	112	$	503

Net cash provided by financing activities decreased by $391 million, during the six months ended June 30, 2003, in comparison to the same period in 2002. The decrease is primarily due to the following:

• The Utility's repayment of $333 million of mortgage bonds in the six months ended June 30, 2002, with no such repayments in 2003; and

• PG&E NEG's reduction of long-term debt issued during the six months ended June 30, 2003, as a result of PG&E NEG's liquidity constraints, discussed above in the "Liquidity and Financial Resources" section of this MD&A.

RESULTS OF OPERATIONS

In this section, PG&E Corporation discusses earnings and the factors affecting them for each operating segment. The table below details certain items from the accompanying Consolidated Statements of Operations by operating segment for the three and six months ended June 30, 2003, and 2002.

					PG&E National Energy Group
(in millions)		Utility		Total PG&E NEG			Integrated Energy & Marketing Activities		Interstate Pipeline Operations			PG&E NEG Elimi- nations			PG&E Corpora- tion, Elimi- nations and Other (1)			Total
Three months ended June 30, 2003
Operating revenues (2)		$	2,730	$		210	$	171	$		59	$		(20)	$		(14)	$		2,926
Operating expenses		1,975		274			217		28			29			(26)			2,223
Operating income (loss)		755		(64)			(46)		31			(49)			12			703
Interest income																		25
Interest expense																		(364)
Other income (expenses), net																		-
Income before income taxes																		364
Income taxes																		145
Income from continuing operations																					219
Net income																		$		227
Three months ended June 30, 2002 (3)
Operating revenues (2)		2,714		245			196		54			(5)			(22)			2,937
Operating expenses		1,655		516			496		25			(5)			(17)			2,154
Operating income (loss)		1,059		(271)			(300)		29			-			(5)			783
Interest income																		32
Interest expense																		(360)
Other income (expenses), net																		(17)
Income before income taxes																		438
Income taxes																		159
Income from continuing operations																				279
Net income																		$		218
Six months ended June 30, 2003
Operating revenues (2)		4,797		469			384		123			(38)			(39)			5,227
Operating expenses		3,993		712			598		55			59			(52)			4,653
Operating income (loss)		804		(243)			(214)		68			(97)			13			574
Interest income																		39
Interest expense																		(739)
Other income (expenses), net																		3
Loss before income taxes																		(123)
Income taxes (benefit)																					(64)
Loss from continuing operations																		(59)
Net loss																		$		(127)
Six months ended June 30, 2002 (3)
Operating revenues (2)		5,167		499			395			113			(9)			(56)			5,610
Operating expenses		2,860		713			662			51			-			(48)			3,525
Operating income (loss)		2,307		(214)			(267)			62			(9)			(8)			2,085
Interest income																			64
Interest expense																			(694)
Other income (expenses), net																			3
Income before income taxes																			1,458
Income taxes																			555
Income from continuing operations																			903
Net income																			$		849
(1)	PG&E Corporation eliminates all inter-segment transactions in consolidation.
(2)	Operating revenues and operating expenses reflect the adoption of a new accounting policy in the third quarter of 2002 implementing a retroactive change from gross to net method of reporting revenues and expenses on trading activities and the netting of certain revenues and expenses, primarily related to hedging activities in the second quarter of 2003. Amounts for trading activities and certain hedging activities for prior periods have been reclassified to conform with the new net presentation.
(3)	Prior period amounts have been restated to reflect the reclassification of USGenNE, Mountain View, ET Canada, and Ohio Peakers operating results in net gains on disposal to discontinued operations.

PG&E Corporation - Consolidated

Overall Results

PG&E Corporation's net income for the three months ended June 30, 2003, was $227 million, in comparison to $218 million for the same period in 2002. PG&E Corporation's net loss for the six months ended June 30, 2003, was $127 million in comparison to net income of $849 million for the same period in 2002.

The significant changes to items affecting net income for the three and six months ended June 30, 2003, in comparison to the same periods in 2002, are summarized in the table below:

		Three months ended		Six months ended
(in millions)		June 30		June 30
PG&E Corporation
	Interest expense	$	(11)	$	(9)
Utility
	Electric revenues	(131)		(672)
	Natural gas revenues	147		302
	Cost of electricity	(10)		(717)
	Cost of natural gas	(122)		(293)
	Operating and maintenance expenses	(128)		(17)
	Depreciation, amortization and decommissioning	(13)		(40)
	Reorganization professional fees and expenses	(47)		(66)
	Interest and other income, net	5		3
	Interest expense	59		102
PG&E NEG
	Operating revenues	(35)		(30)
	Cost of commodity sales and fuel	39		34
	Impairments, write-offs and other charges	235		35
	Operations, maintenance and management expenses	4		(16)
	Administrative and general expenses	(32)		(48)
	Depreciation and amortization	(3)		1
	Interest expense, net	(49)		(141)
	Discontinued operations	10		(104)
	Cumulative effect of changes in accounting principles	61		53

Dividends

PG&E Corporation did not declare any dividends in the first six 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 6 7/8 percent Senior Secured Notes (Notes). See Note 9 of the Notes to the Consolidated Financial Statements for further details. The Note indenture allows PG&E Corporation to declare or pay dividends, under certain conditions, provided that in any case no default is outstanding under the Indenture. The conditions also include: (1) PG&E Corporation achieves an investment-grade credit rating, or (2) following the implementation of the Utility Chapter 11 proceeding, PG&E Corporation pays any dividend from the proceeds of cash distributions to PG&E Corporation from the Utility, or (3) PG&E Corporation me ets certain financial criteria as defined in the Indenture.

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

While in Chapter 11, the Utility is not allowed to pay dividends without Bankruptcy Court approval. In addition, the proposed settlement agreement and Settlement Plan would prohibit the Utility from paying dividends to PG&E Corporation before July 1, 2004. Assuming the proposed 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.

Interest Expense

PG&E Corporation's increase in interest expense for the three and six months ended June 30, 2003, in comparison to the same periods in 2002, was partly due to a write off of $6 million in unamortized loan discount upon the partial repayment of $308 million of PG&E Corporation's original $1 billion credit agreement in 2002. The unamortized loan discount represented the remaining fair value of PG&E NEG options issued in connection with PG&E Corporation's credit agreement.

Utility

Electric Revenues

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

	Three months ended				Six months ended
	June 30,				June 30,
(in millions)	2003		2002		2003		2002
Residential	$	823	$	814	$	1,744	$	1,759
Commercial	1,071		1,115		1,916		1,996
Industrial	351		370		656		705
Agricultural	130		155		198		221
Miscellaneous	353		184		286		223
Direct access credits	(69)		(82)		(150)		(190)
DWR pass-through revenue	(597)		(363)		(1,351)		(743)
Total electric operating revenues	$	2,062	$	2,193	$	3,299	$	3,971

Electric revenues decreased $131 million, or 6 percent, for the three months ended June 30, 2003, and $672 million, or 17 percent, for the six months ended June 30, 2003, in comparison to the same periods in 2002 primarily due to the following:

• Amounts recorded as pass-through revenues to the DWR increased by $234 million for the three months ended June 30, 2003, and $608 million for the six months ended June 30, 2003, in comparison to the same periods 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) changes to the methodology used to calculate DWR pass-through revenues beginning in the third quarter of 2002 (see the "Regulatory Matters" section of this MD&A), (2) an additional bond charge passed through to the DWR, which began in November 2002, and (3) an increase in volume supplied by the DWR.

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 electric customers that cannot be met by utility-owned generation or electricity under contract to the Utility). The Utility resumed procuring 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 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 the DWR's sales to the Utility's customers.

• A lower average sales price 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 surcharges.

• The decrease in electric revenues was partially offset by an increase in electric sales volume due to warmer weather in June 2003 and an increase in the amount recorded in the second quarter of 2003 to include an estimate of $64 million 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 excludes the cost and volume of electricity provided by the DWR to the Utility's customers:

	Three months ended June 30,				Six months ended June 30,
(in millions)	2003		2002		2003		2002
Cost of purchased power	$	584	$	481	$	1,145	$	886
Proceeds from surplus sales allocated to the Utility	(95)		-		(133)		-
Fuel used in own generation	26		24		44		48
Adjustment to purchased power accruals	-		-		-		(595)
Total Cost of Electricity	$	515	$	505	$	1,056	$	339
Average cost of purchased power per kWh	$	0.082	$	0.077	$	0.083	$	0.073
Total purchased power (GWh)	7,099		6,232		13,863		12,138

The Utility's cost of electricity increased $10 million, or 2 percent, for the three months ended June 30, 2003, and $717 million for the six months ended June 30, 2003, in comparison 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 open 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 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 six months ended June 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 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 revenue, which are comprised of bundled gas revenues and transportation service-only revenues:

	Three months ended June 30,				Six months ended June 30,
(in millions)	2003		2002		2003		2002
Bundled gas revenues	$	536	$	372	$	1,485	$	1,145
Transportation service-only revenues	67		79		133		160
Other	65		70		(120)		(109)
Total Natural Gas Revenues	$	668	$	521	$	1,498	$	1,196
Average bundled price of natural gas sold per Mcf	$	8.65	$	6.00	$	8.89	$	6.54
Total bundled gas sales (in millions Mcf)		62		62		167		175

Bundled natural gas revenues increased $164 million, or 44 percent, for the three months ended June 30, 2003, and $340 million, or 30 percent, for the six months ended June 30, 2003, in comparison to the same periods in 2002. Increases for both periods were primarily as a result of a higher average cost of natural gas, which was passed along to customers through higher rates. The average bundled price of natural gas sold increased $2.65 per thousand cubic feet (Mcf), or 44 percent, for the three months ended June 30, 2003, and $2.35 per Mcf, or 36 percent, for the six months ended June 30, 2003, in comparison to the same periods in 2002.

Transportation service-only revenues decreased by $12 million, or 15 percent, for the three months ended June 30, 2003, and $27 million, or 17 percent, for the six months ended June 30, 2003, in comparison to the same periods in 2002. These decreases were primarily due to a decrease in demand for gas transportation services by natural gas-fired electric generators in California.

Other natural gas revenues primarily include balancing account revenues. These revenues decreased by $5 million, or 7 percent, for the three months ended June 30, 2003, and $11 million, or 10 percent, for the six months ended June 30, 2003, in comparison 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 June 30,				Six months ended June 30,
(in millions)	2003		2002		2003		2002
Cost of natural gas sold	$	288	$	172	$	738	$	462
Cost of gas transportation	32		26		68		51
Total Cost of Natural Gas	$	320	$	198	$	806	$	513
Average price of natural gas purchased per Mcf	$	4.65	$	2.77	$	4.42	$	2.64
Total natural gas purchased (in millions Mcf)		62		62		167		175

The Utility's cost of natural gas increased $116 million, or 67 percent, for the three months ended June 30, 2003, and $276 million, or 60 percent, for the six months ended June 30, 2003, in comparison to the same periods in 2002. Increases for both periods were primarily due to an increase in the average market price of natural gas purchased of $1.88 per Mcf, or 68 percent, for the three months and $1.78 per Mcf, or 67 percent, for the six months ended June 30, 2003, in comparison to the same periods in 2002

The Utility's cost to transport gas to its service area increased by $6 million, or 23 percent, for the three months ended June 30, 2003, and $17 million, or 33 percent, for the six months ended June 30, 2003, in comparison 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 fixed transportation on the El Paso Natural Gas Company pipeline.

Operating and Maintenance

The Utility's operating and maintenance expenses increased $128 million, or 20 percent, for the three months ended June 30, 2003, in comparison to the same period in 2002. This increase was primarily due to increases in employee benefit plan-related expenses, public purpose programs spending, customer-related costs, and other administrative and general costs.

The Utility's operating and maintenance expenses increased $17 million, or 1 percent, for the six months ended June 30, 2003, as compared to the same period in 2002. This increase was primarily due to increases in employee benefit plan-related expenses, public purpose programs spending, customer-related costs, and maintenance expenses due to maintenance performed during the scheduled refueling outage at the Diablo Canyon Power Plant (DCPP) in the first quarter of 2003. These increases were partially offset by lower recorded costs for environmental matters, and a decrease in the recorded liabilities for regulatory matters due to FERC and CPUC decisions on previous transmission owner rate cases and other matters.

Depreciation, Amortization, and Decommissioning

Depreciation, amortization, and decommissioning expenses increased $13 million, or 4 percent, for the three months ended June 30, 2003, as compared to the same period in 2002 primarily due to an overall increase in the Utility's plant assets.

Depreciation, amortization, and decommissioning expenses increased $40 million, or 7 percent, for the six months ended June 30, 2003, as compared to the same period in 2002. This increase was due mainly to an increase in amortization of the rate reduction bond regulatory asset, which began at the end of January 2002, and an overall increase in the Utility's plant assets. Amortization of the rate reduction bond regulatory asset for the six months ended June 30, 2003, increased $20 million from the same period in 2002. The increase reflects the amortization of the regulatory asset for all six months in 2003, in comparison to the amortization of the regulatory asset for only five months in 2002.

Interest Income

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 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 increased $1 million, or 5 percent, for the three months ended June 30, 2003, and decreased $10 million, or 24 percent, for the six months ended June 30, 2003, in comparison to the same periods in 2002. The decrease was due primarily to lower average interest rates earned on the Utility's short-term investments.

Interest Expense

The Utility's interest expense decreased $59 million, or 21 percent, for the three months ended June 30, 2003, and $102 million, or 19 percent, for the six months ended June 30, 2003, in comparison to the same periods in 2002. Decreases for both periods were due to a reduction of interest on rate reduction bonds and a lower level of unpaid debts accruing interest.

Reorganization Fees and Expenses

In accordance with 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 $65 million for the three months ended June 30, 2003, and $100 million for the six months ended June 30, 2003.

Dividends

While in Chapter 11, the Utility is not allowed to pay dividends without Bankruptcy Court approval. Under the proposed settlement agreement and 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 settlement agreement is approved and the Settlement Plan implemented, the Utility does not anticipate paying a dividend until the later part of 2005.

PG&E NEG

PG&E NEG has experienced significant impacts to its results of operations from various acquisitions and disposals, and more recently from its efforts to raise cash and reduce indebtedness through sale, transfer, or abandonment of assets.

Overall Results

PG&E NEG's net loss for the three months ended June 30, 2003, decreased by $86 million, or 36 percent, in comparison to the same period in 2002. PG&E NEG's net loss for the six months ended June 30, 2003, increased by $320 million, or 157 percent, in comparison to the same period in 2002.

The three months ended June 30, 2003 included a net loss recognized on disposals of assets held for sale of $9 million related to Dispersed Generating Company's Ohio generating plants. The six months ended June 30, 2003, included a net gain recognized on disposals of assets held for sale of $7 million related to the gain on sale of Mountain View of $19 million, offset by additional losses on the sale of ET Canada of $3 million and net loss on Dispersed Generating Company's plants discussed above. No gains or losses on disposal of assets held for sale were reflected in the comparative periods in 2002. In addition, losses from discontinued operations of assets held for sale were $4 million for the three months ended June 30, 2003, with no earnings reported in the comparative period in 2002. Losses from discontinued operations of assets held for sale were $104 million for the six months ended June 30, 2003, a decrease of $111 million in comparison to the same period in 2002.

PG&E NEG's pre-tax operating losses were $165 million for the three months ended June 30, 2003 and $458 million for the six months ended June 30, 2003. The decrease in pre-tax operating losses of $158 million or 49 percent for the three months ended June 30, 2003, in comparison to the same period in 2002 was principally due to a $265 million impairment charge related to project development, turbines and other related equipment costs in the second quarter of 2002, in comparison to a $30 million charge related to a DTE-Georgetown toll termination fee in the second quarter of 2003. The increase in pre-tax operating losses of $170 million or 59 percent for the six months ended June 30, 2003, in comparison to the same period in 2002 was principally due to increased interest expenses of $140 million primarily due to new merchant plants in operation that had previously been in construction and higher interest rates on a greater level of debt outstanding. Most of PG&E NEG's debt is currently in default and is further discussed in Note 3 of the Notes to the Consolidated Financial Statements. In addition, administrative and general expense increased $48 million or 200 percent for the six months ended June 30, 2003, in comparison to the same period in 2002, due to costs associated with PG&E NEG's debt restructuring efforts.

Gross margins decreased $7 million or 5 percent for the three months ended June 30, 2003, and decreased $14 million or 5 percent for the six months ended June 30, 2003, in comparison to the same periods in 2002 primarily due to the winding down of PG&E NEG's energy trading operations. Gross margin is defined as the difference between generation, transportation, and trading revenues versus cost of commodity sales and fuel. Administrative and general expense increased $32 million or 188 percent for the three months ended June 30, 2003 in comparison to the same period in 2002 due to costs associated with PG&E NEG's debt restructuring efforts. Additionally, interest expenses increased $51 million or 93 percent for the three months ended June 30, 2003, in comparison to the same period in 2002, primarily due to new merchant plants in operation that had previously been in construction and higher interest rates on a greater level of debt outstanding. For the six months ended June 30, 2003, operation, maintenance, and management expenses increased $16 million or 9 percent, in comparison to the same period in 2002, primarily due to various merchant facilities in operation that had previously been in construction, offset by less impairments and write-offs in 2003. During the first six months of 2003, $230 million of impairment and write-offs were charged to income as a result of the consolidation and impairment of Attala Generating, the Shaw litigation settlement, and the DTE-Georgetown toll termination fee as further discussed in Note 3 of the Notes to the Consolidated Financial Statements. In comparison, impairments and write-offs totaling $265 million were charged to income during the first six months of 2002 related to project development, turbines and other related equipment costs. Tax benefits recorded during the first six months of 2003 of $39 million reflect adjustments to the PG&E NEG's tax valuation allowances with no such tax valuation allowance recorded in the comparative period in 2002. Most of PG&E NEG's debt is currently in default and is further discussed in Note 3 of the Notes to the Consolidated Financial Statements.

Operating Revenues

PG&E NEG's operating revenues decreased $35 million or 14 percent for the three months ended June 30, 2003, and $30 million or 6 percent for the six months ended June 30, 2003, in comparison to the same periods in 2002. These decreases relate primarily to the Integrated Energy and Marketing Activities segment and are primarily a result of the activities associated with the winding down of PG&E NEG's energy trading operations. Interstate Pipeline Operations operating revenues increased $5 million or 9 percent for the three months ended June 30, 2003, and $10 million or 9 percent for the six months ended June 30, 2003, in comparison to the same periods in 2002, primarily due to the addition of the North Baja pipeline operations.

Operating Expenses

PG&E NEG's operating expenses decreased $242 million or 47 percent in the three months ended June 30, 2003, in comparison to the same period in 2002. This decrease occurred primarily as a result of $265 million impairments and write-offs related to project development, turbines and other related equipment costs charged to income in the second quarter of 2002, in comparison to a $30 million charge related to a DTE-Georgetown toll termination fee in 2003. In addition, the cost of commodity sales and fuel decreased $39 million, or 36 percent, in the three months ended June 30, 2003, in comparison to the same period in 2002 due to the winding down of PG&E NEG's energy trading operations. Offsetting these decreases in operating expenses was an increase in administrative and general expenses of $32 million or 188 percent for the three months ended June 30, 2003, in comparison to the same period in 2002 due to costs associated with PG&E NEG's debt restructuring efforts.

PG&E NEG's operating expenses decreased $1 million or less than 1 percent in the six months ended June 30, 2003, in comparison to the same period in 2002. This decrease occurred primarily as a result of reduced cost of commodity sales and fuel expenses associated with the winding down of PG&E NEG's energy trading operations. Operation, maintenance, and management expenses increased $16 million, or 9 percent, for the six months ended June 30, 2003, in comparison to the same period in 2002, primarily due to new merchant plants in operation that had previously been in construction. In addition, administrative and general expense increased $48 million or 200 percent for the six months ended June 30, 2003, in comparison to the same period in 2002, due to costs associated with PG&E NEG's debt restructuring efforts. Offsetting these increases in operating expenses was a decrease in impairments and write-offs charged to income of $35 million for the six months ended June 30, 2003, in comparison to the same period in 2002 as discussed above.

REGULATORY MATTERS

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

The Utility is the only subsidiary with significant regulatory proceedings or issues at this time. 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. Regulatory proceedings associated with electric industry restructuring are further discussed in Note 6 of the Notes to the Consolidated Financial Statements.

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 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 settlement agreement, including when and whether it will be approved. For further discussion, see Notes 2 and 6 of the Notes to the Consolidated Financial Statements.

DWR Revenue Requirement and Operating Agreement

Because the Utility acts as a collection agent for the DWR, amounts collected on behalf of the DWR (related to its revenue requirement) are excluded from the Utility's revenues. Until the CPUC modifies the current frozen rate structure or until the approval of the proposed settlement agreement and new rates under that settlement are implemented, changes to the DWR's 2001, 2002, or 2003 revenue requirement may materially affect the Utility's future earnings.

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 costs associated with the DWR contracts allocated to the Utility's customers effective 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. (The December 2002 operating order required the Utility to perform the operational, dispatch, and administrative functions for the DWR's allocated contracts beginning on January 1, 2003.) The operating agreement provides that the Utility will begin passing through additional revenues to the DWR consistent with the DWR's October 2002 and March 2003 requests for amendments to the formula that determines the amount of remittances to the DWR contained in the May 2002 servicing order but subject to the outcome of the CPUC's con sideration of the DWR's requests. As of June 30, 2003, the Utility had accrued an additional $516 million, pre-tax, obligation for pass-through revenues to the DWR. The Utility had accrued $369 million, pre-tax, at December 31, 2002, and $539 million, pre-tax, at March 31, 2003 for these additional pass-through revenues to the DWR. During the second quarter of 2003, the Utility remitted $74 million of these pass-through revenues to the DWR and accrued an additional $51 million. The ultimate remittance of the $516 million amount accrued as of June 30, 2003, depends upon whether the CPUC grants the DWR's request for changes to the May 2002 servicing order (which was revised in December 2002) and whether such changes would be retroactive to January 2001, the date that the DWR began purchasing power for the Utility's customers.

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 anticipating receiving by approximately $1 billion. The CPUC is responsible for determining how to allocate the reduced revenue requirement among the customers of the three California IOUs. The requested reduction expressly assumes that the Utility would remit an additional estimated cash payment of $539 million, which was accrued as of March 31, 2003, to the DWR in 2003. The Administrative Law Judge (ALJ) in this proceeding indicated that the $539 million assumed remittance amount is an estimate and not a final number. The ALJ also indicated that, in connection with the proposed 2003 DWR revenue requirement reduction, the CPUC may consider reducing utility rates overall in order to pass-through the savings to customers. The CPUC expects to consider a proposed decision during the third quarter of 2003. On August 1, 2003, another CPUC ALJ issued a draft decision that, if approved by the CPUC, would modify the May 2002 and December 2002 DWR servicing orders to require the Utility to remit an additional cash payment to the DWR for the period retroactive to January 2001, as discussed above. The draft decision would not specify the amount to be remitted but instead defers the issue to the 2003 DWR supplemental revenue requirement proceeding, where offsetting reductions to the DWR's revenue requirements and remittances for 2003 are being considered. The draft decision would not determine whether the Utility should pay interest on the additional payment, but would defer to both the DWR and the Utility to resolve the issue, subject to CPUC determination if the parties cannot agree. The draft decision is subject to comment by parties before being considered by the CPUC. A separate proceeding will consider a revision or adjustment for the revenue requirements remitted to the DWR for 2002 and 2001 costs. At that time, the CPUC may also consider a revision or adjustment to the allocation of the DWR's 2003 revenue requirement. The Utility cannot predict the ultimate outcome of this matter.

In July 2003, the DWR also issued its proposed statewide revenue requirement for 2004. In this proposed revenue requirement, the DWR states that it expects to collect $4.7 billion for power charge-related costs in 2004 from the customers of the three IOUs. This reflects an increase of approximately $1.3 billion from the DWR's revised 2003 revenue requirement. The DWR plans to file the proposed 2004 revenue requirement with the CPUC in August 2003. The CPUC would then be responsible for allocating the proposed 2004 revenue requirement among the customers of the IOUs.

The Utility has a lawsuit pending in a California court, asking that the DWR be precluded from imposing its revenue requirements on the Utility and its customers until the DWR can demonstrate that its revenue requirements are "just and reasonable," as legally required. The lawsuit is scheduled to be considered by the court during the third or fourth quarter of 2003.

DWR Bond Charge

In October 2002, the CPUC issued a decision that, in part, imposes bond 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 passed through approximately $183 million in bond-related charges during the six months ended June 30, 2003.

In July 2003, the DWR released its proposed statewide revenue requirement for 2004. In this proposed revenue requirement, the DWR states that it expects to collect $0.8 billion for bond-related costs in 2004 from the customers of the three IOUs. The DWR plans to file the proposed 2004 revenue requirement with the CPUC in August 2003. The CPUC would then be responsible for allocating the proposed 2004 bond charge-related revenue requirement among the customers of the IOUs.

While the Utility's overall rates remain frozen, any increase in bond charges from bundled customers compared to 2003 levels would reduce the amount of revenue available to restore the Utility's financial health and recover previously written-off under-collected electricity procurement and transitions costs, unless offset by reductions in other DWR revenue requirements or other components of the Utility's rates.

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. This decision required the Utility, along with the other IOUs, to begin performing all the day-to-day scheduling, dispatch, and administrative functions associated with the DWR contracts allocated to the IOUs' respective electric resource portfolios on January 1, 2003. The DWR retains legal and financial responsibility for these contracts.

Under the proposed settlement agreement, the Utility would agree to accept an assignment of or to assume legal and financial responsibility for the DWR contracts only if (1) the Utility receives a long-term issuer credit rating of at least A from S&P and a credit rating of at least A2 from Moody's after giving effect to such assignment or assumption, (2) the CPUC first makes a finding that the DWR allocated contracts are just and reasonable, and (3) the CPUC first acts to ensure that the Utility receives full and timely rate recovery of all costs of the DWR contracts over their life without further review. The CPUC would retain the right to review administration and dispatch of the DWR contracts consistent with applicable law. The State of California has stated publicly that it does not intend to transfer full legal title of, and responsibility for, the DWR electricity contracts to the IOUs until they are in a position where they will be financially able to absorb the contracts. However, if the pro posed settlement agreement is not approved and either the State of California or the CPUC grants the DWR the authority to transfer legal title of the DWR contracts to the Utility without having first met the Utility's conditions, the Utility's results of operations could be adversely affected.

Electricity Procurement

In October 2002, the CPUC issued a decision ordering the Utility to resume full procurement of electricity on January 1, 2003. In December 2002, the CPUC issued an interim opinion adopting the revised electricity procurement plan for 2003 that the Utility submitted in 2002, with modifications, and authorized the Utility to enter into contracts designed to hedge its residual net open position in 2003 and the first quarter of 2004.

In June 2003, the CPUC issued a decision denying rehearing and modifying the October and December 2002 decisions. The June 2003 decision reaffirms the CPUC's right to review the reasonableness of the Utility's activities in connection with contract management and least-cost dispatch. In June 2003, the CPUC also issued a decision modifying the December 2002 decision to set the maximum annual procurement disallowance for administration of all contracts and least-cost dispatch for the Utility at $36 million. This "disallowance cap" is subject to true-up for the Utility's adopted annual administrative costs of management procurement activities in the 2003 GRC. The disallowance cap applies to contract administration and least-cost dispatch. 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.

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. 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 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.) The CPUC will finalize the Utility's starting ERRA revenue requirement and ERRA trigger threshold after it reviews the Utility's ERRA application. The Utility cannot predict w hen or whether it will reach the trigger threshold.

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, approve as reasonable the Utility's ERRA recorded costs for the period from January 2003 through May 2003, and approve the Utility's proposed revenue requirement and rate design for 2004 ongoing Competition Transition Charges (CTC).

In June 2003, the CPUC issued a decision 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 per year. By the end of 2017, the Utility must be procuring at least 20 percent of its total electricity from renewable resources. The decision states that the Utility is not obligated to procure additional renewable energy under the RPS until creditworthy and that the Utility will accumulate an Annual Procurement Target (APT) based on 1 percent of annual retail sales, starting in 2003, until it receives an investment grade credit rating. When the Utility receives an investment grade credit rating it will be required to enter into procurement 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 kilowatt-hour (kWh), subject to an annual penalty cap of $25 million.

The Utility filed its long-term procurement plan (long-term plan), covering the next 20 years, on April 15, 2003. The Utility's long-term plan states that certain important policy issues, including the restoration of the Utility's financial health and investment grade credit rating, should be resolved before the CPUC can adopt a credible long-term plan for the Utility. While the long-term plan states that there is no immediate need for the Utility to construct or make long-term commitments to new resources, it indicates that the Utility's role in future generation development will be directly impacted by its credit rating. The CPUC has stated that it plans to issue a final decision on the Utility's long-term procurement plan in November 2003.

The Utility filed its 2004 short-term procurement plan in May 2003.

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

In April 2003, the CPUC's Office of Ratepayer Advocates (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 settlement agreement in the Utility's Chapter 11 proceeding, 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 proceeding. The decision does not change retail electric rates and the Utility does not expect it to have a material impact on its results of operations. Instead, the decision defers consideration of future rate changes until the CPUC addresses the status of the retail rate freeze. The CPUC also deferred addressing recovery of the Utility's past unrecovered generation-related costs. 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 April 2002 retained generation decision.

In November 2002, the Utility filed its 2003 GRC application. In that application, the Utility forecasted a $1 billion revenue requirement for utility retained generation. This forecast generation revenue requirement excluded fuel and purchased power expense, and the DWR and nuclear decommissioning revenue requirements. Recovery of fuel and purchased power generation-related costs for 2003 was addressed in the Utility's ERRA proceeding (see "Electricity Procurement" above).

In July 2003, the Utility filed a motion for approval of a proposed settlement agreement reached with the ORA and other parties that had originally disputed the Utility's $1 billion 2003 generation revenue requirement request in its 2003 GRC proceeding. The proposed settlement agreement sets a 2003 non-fuel generation revenue requirement of $955 million and provides for attrition adjustments in 2004, 2005 and, if applicable, 2006 (depending on whether the CPUC authorizes an additional attrition year in 2006) based on the Consumer Price Index (CPI), with a minimum increase of 1.5 percent and a maximum increase of 3.0 percent. The proposed settlement agreement is subject to CPUC approval. The settling parties have requested expedited approval of the settlement, but there is some likelihood that the CPUC will wait to act on the settlement in the final decision issued in the 2003 GRC. The CPUC announced that it will hold a series of meetings and hearings on the Utility's GRC and proposed Chapter 11 settle ment during August 2003. A decision in the GRC proceeding is expected in the first quarter of 2004.

Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, the Utility's adopted 2002 retained generation rate base of $1.7 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 would result in the recording of an additional regulatory asset of $1.3 billion.

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 November 2002, the CPUC issued a decision establishing a cost responsibility surcharge (CRS) to implement surcharges applicable to direct access customers, subject to an overall cap of $0.027 per kWh. In December 2002, the CPUC issued a decision requiring the utilities to implement the $0.027 per kWh surcharge beginning January 1, 2003.

In July 2003, the CPUC issued a decision that continues to keep the existing direct access CRS cap of $0.027 per kWh after July 1, 2003, subject to possible future prospective adjustment in the annual DWR revenue requirement proceedings, as deemed necessary to pay off the direct access CRS under-collection by 2011. This decision also changed the order of the collection for direct access CRS components to (1) DWR Bond Charge, (2) CTC, which is the ongoing above market portion of certain utility-related generation costs, and (3) DWR Power Charge. The finalization of the CTC element for year 2004 and thereafter will be addressed in the ERRA proceeding.

To the extent the CRS cap results in an under-collection of DWR charges, the shortfall would have to be remitted 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 revenues to the DWR, the Utility expects those remittances to 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.

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 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 another IOU, 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. As such, the Utility has not recorded a regulatory liability or a refund reserve for these surcharge revenues, or any portion thereof, in its financial statements. From January 2001 to June 30, 2003, the Utility recognized total surcharge revenues of $6.5 billion, pre-tax.

The California Supreme Court is currently considering the authority of the CPUC to enter into a settlement agreement with SCE that allows SCE to recover under-collected procurement and transition costs in light of the provisions of AB 1890. In May 2003, the California Supreme Court heard oral arguments from SCE, the CPUC, and TURN on this matter. It is expected that the Court will issue a ruling by August 27, 2003. Either in response to judicial decisions such as this one, or on its own initiative, it is possible that at some future date the CPUC may change its interpretation of law or otherwise seek to change the Utility's overall retail electric rates retroactively. (See further discussion in the "Recovery of Transition Costs and Surcharge Revenues" in Note 6 of the Notes to the Consolidated Financial Statements). The Utility has not provided reserves for potential refunds of any of these revenues as of June 30, 2003.

Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, 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 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 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 through 2005. 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 November 2002, the Utility requested a $447 million increase in its electric distribution revenue requirements and a $105 million increase in its gas distribution revenue requirements over the current authorized amounts. The Utility also will seek an attrition rate adjustment (ARA) increase for 2004 and 2005. The ARA mechanism is designed to avoid a reduction in earnings in years between GRCs to reflect increases in rate base and expenses.

In December 2002, the CPUC ordered that the 2003 GRC be effective January 1, 2003, despite the CPUC not issuing a final decision on the 2003 GRC until a current target date of February 5, 2004.

In April 2003, the ORA provided to the Utility and other parties the ORA's report on the Utility's 2003 GRC application. In its report, the ORA recommends an increase of $170 million in electric base revenues and an increase in gas base revenues of $3.7 million over the current authorized amounts.

The two largest components of the difference between the Utility's request and the ORA's recommendation are administrative and general expenses, which comprise 35 percent of the total difference, and depreciation expenses, which comprise 23 percent of the total difference. In addition, the ORA recommended that the Utility's next test year GRC be delayed until 2007, rather than 2006, and that the Utility file an ARA request for 2006.

The CPUC may accept all, part, or none of the ORA's recommendations. The Utility cannot predict the amount of revenue requirements, if any, the CPUC will authorize for the 2003 through 2005 period. If the CPUC issues an adverse decision, 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.

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. The Utility cannot predict when the CPUC will rule upon this application for rehearing, nor whether any decision the CPUC ultimately issues will have a material impact on the Utility's results of operations or financial condition.

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 and held open the case to address the impact on the Utility's ROE, costs of debt and preferred stock, and ratemaking capital structure of the implementation and financing of a Chapter 11 plan of reorganization. Subsequently, in February 2003, the Utility filed a petition to modify the November 2002 decision to waive the normal requirement for the Utility to file a test year 2004 Cost of Capital application. In May 2003, the CPUC granted the Utility's request, exempting it from filing a test year 2004 Cost of Capital application.

Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, the CPUC would set the Utility's cost of capital such that from January 1, 2004, until the Utility obtains credit ratings of at least A- from S&P or A3 from Moody's, the authorized ROE would be no less than 11.22 percent and, except for 2004 through 2005, the authorized equity ratio would be no less than 52.00 percent. (For 2004 and 2005, the equity ratio would equal the greater of the Forecast Average Equity Ratio, or 48.60 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 buyers. On December 12, 2002, a FERC ALJ issued an initial decision finding that power companies overcharged the utilities, the State of California, and other buyers from October 2, 2000, to June 2001 by $1.8 billion, but that California buyers still owe the power companies $3.0 billion, leaving $1.2 billion in unpaid bills. The time period reviewed in the FERC hearings excludes the claims for refunds for overcharges that occurred before October 2, 2000, and after June 2001 when the DWR entered into contracts to buy electricity.

In March 2003, the FERC confirmed most of the ALJ's findings, but partially modified the refund methodology. A FERC spokesperson has estimated the total potential refunds statewide, using the modified methodology, at $3.3 billion. The actual refunds will not be determined until the FERC issues a final decision, which is expected by September 2003.

The Utility has recorded $1.8 billion of claims filed by various power 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 recalculation of market prices according to 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 or any other FERC orders could result in an additional several hundred million dollar decrease in the amount of the generators' claims offset by the amount of any additional fuel cost allowance for generators accepted by the FERC. If these claims are reduced, it would also reduce the Utility's previously written-off under-collected purchased power and transition costs.

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 Power Exchange (PX) tariffs related to market manipulation during the summer of 2000. The Utility was named as one of the companies in these orders, however due to the limited dollar amount of the transactions identified as possibly in violation of the tariffs, the Utility does not expect the outcome to have a material adverse impact on its consolidated financial position or results of operations.

The FERC, also in June 2003, began an investigation of why companies should not disgorge profits related to bidding for electricity in violation of ISO and PX tariffs during the period from May to September 2003. The Utility expects that the amount it would be required to pay, if any, would be immaterial and substantially less than the refunds it would receive from other companies. Therefore, the Utility does not expect the outcome to have a material adverse impact on its consolidated financial position or results of operations.

Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, PG&E Corporation and the Utility would agree to continue to cooperate with the CPUC and the State of California in seeking refunds from generators and other energy suppliers. The net after-tax amount of any refunds, claim offsets, or other credits from generators or other energy suppliers relating to the Utility's PX, ISO, QF, or energy service provider costs that the Utility actually realizes in cash or by offset of creditor claims in the Utility's Chapter 11 case would be applied by the Utility to reduce the outstanding balance of the $3.7 billion, pre-tax, regulatory asset to be created under the proposed settlement agreement.

El Paso Settlement

In June 2003, the Utility, along with a number of other parties, entered into a final settlement with El Paso to settle claims against El Paso relating to the sale or delivery of natural gas and/or electricity to or in the western United States, including claims that El Paso took actions that resulted in artificially inflated gas prices during the California energy crisis of 2000 and 2001. The settlement resolves all potential and alleged causes of action against El Paso for its part in manipulation of gas and electric commodity and transportation market during the period September 1996 to March 2003. Under the settlement's terms, El Paso will provide $1.5 billion in cash and non-cash consideration. Of that total, approximately $600 million will be paid up front, and approximately $900 million over 15 years to 20 years. El Paso also agreed to provide pipeline capacity to California, and to ensure specific reserve capacity for the Utility, if needed. The exact amounts allocated to each CPUC jurisdict ional utility is detailed in the Master Settlement Agreement and delineated pursuant to the Allocation Agreement. The precise means of distribution will be determined by the CPUC, consistent with applicable law, pursuant to CPUC ratemaking and accounting policies, procedures, and orders that have been or will be established by the CPUC. The Utility's gas ratepayer portion of the refund is expected to be approximately $80 million and the electric portion of the refund is expected to be approximately $216 million. The CPUC expects to complete the final allocation of these refunds during the fourth quarter of 2003. The agreement is now subject to the approval by the FERC and the San Diego County Superior Court.

Under the proposed settlement agreement in the Utility's Chapter 11 proceeding, the Utility would agree to apply future El Paso cash payments associated with electric claims to reduce the $3.7 billion, pre-tax, regulatory asset to be created under the proposed settlement agreement.

Gas Accord II

In 1998, the Utility implemented a ratemaking pact called the Gas Accord, under which the Utility's gas transportation and storage services were separated for ratemaking purposes from its distribution services. The Gas Accord changed the terms of service and rate structure for gas transportation, allowing residential and small commercial customers (core customers) to purchase gas from competing suppliers, and establishing gas transportation rates through 2002 and gas storage rates through March 2003. In addition, the Gas Accord established an incentive mechanism whereby the Utility recovers its core procurement costs. Under the Gas Accord, the Utility is at risk for recovery of its gas transportation and storage costs and does not have regulatory balancing account protection for over-collections or under-collections of revenues.

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 gas transmission 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 Gas Accord II amended application proposed for 2004 requests a rate increase, calculated on a demand or throughput forecast basis. In addition, for the 12-month period ending December 31, 2004, for transmission 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 contracted. 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 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 adopted by the CPUC in setting rates. In any of these cases, the Utility's financial condition and res ults of operations could be adversely affected. A decision in this proceeding is expected in early October 2003. Until the CPUC issues a decision, the existing 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. On March 21, 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. The CPUC has delayed action on these proceedings and the Utility has not included any earnings associated with incentives in the Utility's Consolidated Statements of Income.

On March 13, 2002, an ALJ for the CPUC requested comments on whether incentives adopted for pre-1998 energy efficiency programs should be reduced or eliminated for claims in future years. Out of the total $106 million in shareholder incentives claimed by the Utility for its 2003, 2002, 2001, and 2000 AEAP filings, $74 million is related to pre-1998 energy efficiency programs. The CPUC has not yet acted on the comments. The ALJ has indicated that the CPUC will act on incentives for the low-income programs ($1.6 million) this summer, and has taken no action on the post-1997 energy efficiency programs ($30 million). The 2003 AEAP hearing process began with a pre-hearing conference on July 24, 2003. The 2003 AEAP is not consolidated with the 2002, 2001, and 2000 AEAPs.

Under the proposed 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.

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 Application

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 seeks 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 anticipates recovering $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. The Utility proposes continuing to collect the revenue requirement through a charge in electric rates, and to record the revenue requirement and the associated revenues in a balancing account.

In July 2003, the CPUC issued a proposed decision adopting 2003 revenue requirements of $18.4 million for decommissioning the Humboldt Bay Power Plant (HBPP) and $8.3 million for Humboldt SAFSTOR operating and maintenance costs. In the same proposed decision, the CPUC recommended no additional revenue requirement for decommissioning the DCPP, 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 currently adopted revenue requirement of $31.2 million. The CPUC expects to issue a final decision later in 2003.

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.

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 six-month period from January 1, 2003, t hrough June 30, 2003, was $48 million.

Issues that may be resolved during the second phase of the proceeding in early 2003 include items that could involve additional revenues at risk such as demographic revisions to baseline allowances, special allowances, and changes to baseline territories or seasons. The Utility estimates additional annual electric revenue shortfalls from this second phase, if adopted, of $63 million, plus $10 million in administration costs spread out over three to five years.

The Utility cannot predict what the 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 uses derivatives for both non-trading (i.e., risk mitigation) and trading (i.e., speculative) purposes. The Utility uses derivatives for non-trading purposes only. PG&E Corporation and the Utility may use energy and financial derivatives and other instruments and agreements 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. Additionally, PG&E Corporation may engage in trading activities for purposes of generating profit, gathering market intelligence, creating liquidity, and maintaining a market presence. These instruments are used in accordance with approved risk management policies adopted by a senior officer-level risk oversight committee. Derivative activity is permitted only after the risk oversight committee approves appropriate risk limits for such activity. The organizational unit proposing the activity must succe ssfully demonstrate that there is a business need for such activity and that the market risks will be adequately measured, monitored, and controlled.

As discussed in the "Liquidity and Financial Resources" section of the MD&A and Note 3 of the Notes to the Consolidated Financial Statements, PG&E NEG financial results will no longer be consolidated with those of PG&E Corporation following the July 8, 2003, Chapter 11 filing of PG&E NEG. Upon deconsolidation, the only risk management activities reported will be related to Utility non-trading activities.

The activities affecting the estimated fair value of trading activities and the non-trading activities balances, included in net PRM assets and liabilities, are presented below.

	Three Months Ended		Three Months Ended
	June 30, 2003(1)		June 30, 2002 (1)
(in millions)
Fair values of trading contracts at beginning of period	$	11	$	31
Net (gain) loss on contracts settled during the period	7		(34)
Fair value of new contracts when entered into	-		-
Other changes in fair values	(46)		2
Fair values of trading contracts outstanding at end of period		(28)	(1)
Fair values of non-trading contracts outstanding at end of period		(278)	(216)
Net price risk management liabilities at end of period		(306)		(217)
Net price risk management liabilities held for sale	(392)		-
Net price risk management assets (liabilities) reported on the   Consolidated Balance Sheets	$	86	$	(217)

	Six months ended		Six months ended
	June 30, 2003 (1)		June 30, 2002 (1)
(in millions)
Fair values of trading contracts at beginning of period	$	(22)	$	33
Net (gain) loss on contracts settled during the period	40		(78)
Fair value of new contracts when entered into	-		-
Other changes in fair values	(46)		44
Fair values of trading contracts outstanding at end of period		(28)	(1)
Fair values of non-trading contracts outstanding at end of period		(278)	(216)
Net price risk management liabilities at end of period		(306)		(217)
Net price risk management liabilities held for sale	(392)		-
Net price risk management assets (liabilities) reported on the   Consolidated Balance Sheets	$	86	$	(217)
(1) For the three and six months ended June 30, 2003, and 2002, the fair value of all new contracts when entered into was zero.

PG&E Corporation and the Utility estimate the gross mark-to-market value of its non-trading and trading contracts at June 30, 2003, using the mid-point of quoted bid and ask prices, where available. When market data are not available, PG&E Corporation and the Utility use models that estimate forward power prices using the mid-point of the marginal cost curve (the lowest variable cost of generation available in a region) and the forecast curve (the price at which a generation unit will recover its capital costs and a return on investment). Interpolation methods are used for intermediate periods when broker quotes are unavailable. The gross mark-to-market valuation is then adjusted for the time value of money, creditworthiness of contractual counterparties, market liquidity in future periods, and other adjustments necessary to determine fair value. Most of PG&E Corporation's and the Utility's risk management models are reviewed by or purchased from third-party experts in specific derivative applications.

The following table shows the fair value of PG&E Corporation's trading contracts grouped by maturity at June 30, 2003.

		Fair Value of Trading Contracts (1)
Source of Prices Used in    Estimating Fair Value		Maturity Less than One Year		Maturity One-Three Years		Maturity Four-Five Years		Maturity in Excess of Five Years		Total Fair Value
(in millions)
Actively quoted markets (2)		$	18	$	8	$	-	$	-	$	26
Provided by other external sources		34		(70)		(10)		3		(43)
Based on models and other
valuation methods		(31)		(34)		(17)		71		(11)
Total Mark-to-Market		$	21	$	(96)	$	(27)	$	74	$	(28)
(1)	Excludes all non-trading contracts, including non-trading contracts that receive mark-to-market accounting treatment.
(2)	Actively quoted markets are exchange traded quotes.

The amounts disclosed above are not indicative of likely future cash flows. The future value of trading contracts may be impacted by changes in underlying valuations, new transactions, market liquidity, and PG&E Corporation's risk management portfolio needs and strategies.

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. These market risks may impact PG&E Corporation's and its subsidiaries' assets and trading portfolios. As of July 8, 2003, the date of PG&E NEG's Chapter 11 filing, PG&E Corporation no longer will retain significant influence over PG&E NEG. As of this date, PG&E Corporation will account for its investment in PG&E NEG under the cost method of accounting. Consequently, PG&E NEG'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. Below are descriptions of the Utility's and PG&E NEG's specific price risks.

Also described below is the value-at-risk methodology, which is PG&E Corporation's and the Utility's method for assessing the prospective risk that exists within a portfolio for price risk.

Utility Price Risk

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.

Utility Electric Commodity Price Risk

Purchased Power - In compliance with regulatory requirements, the Utility manages commodity price risk independently from the activities in PG&E Corporation's unregulated businesses. The Utility also reports its commodity price risk separately for its electric and natural gas businesses.

During 2001 and 2002, the DWR was responsible for procuring electricity required to cover the Utility's net open position. Under AB 1X, the DWR was prohibited from entering into new agreements to purchase electricity to meet the Utility's net open position after December 31, 2002. The DWR, however, remains legally and financially responsible for electricity contracts that it entered into before December 31, 2002, (existing contracts), and the Utility still relies on electricity provided by these contracts to service a significant portion of its total load. The Utility bills its customers for these DWR electricity purchases under existing contracts and remits amounts collected to the DWR based on the DWR's CPUC-approved revenue requirement. For further discussion, see "Allocation of DWR Electricity to Customers of the IOUs" in Note 6 of the Notes to the Consolidated Financial Statements and the "Regulatory Matters" section of this MD&A.

The CPUC is obligated to increase the Utility's rates if the Utility's available revenues do not cover the Utility's procurement costs, and this shortfall exceeds 5 percent of the Utility's prior year's generation revenues, excluding amounts collected for the DWR. Additionally, the Utility is exposed to price risk to the extent that the cost of new electricity purchases increases, or the revenue from new wholesale sales decreases to the point where costs exceed available revenues. Furthermore, changes in the cost of new electricity purchases also may impact the amount of previously written-off purchased power and transition costs that the Utility is able to recover. For further discussion, see "Electricity Procurement" in the "Regulatory Matters" section of this MD&A.

During the last half of 2002, SB 1976 and CPUC orders were approved that required the California IOUs, including the Utility, to resume responsibility for procuring the electricity to meet the residual net open position by January 1, 2003.

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. In June 2003, the CPUC modified a December decision regarding the Utility's maximum annual procurement disallowance for administration of all contracts and least-cost dispatch of resources. This June decision limits this annual disallowance 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. If the CPUC changes the maximum annual procurement disallowance in the future, the Utility could face additional exposure to electric commodity price risk.

The residual net open position is expected to increase over time due to periodic expirations of existing and DWR allocated procurement contracts. The Utility currently expects that electricity will continue to be available for purchase in quantities sufficient to satisfy the residual net open position. However, if the western region of the United States develops a greater need for new generation for reliability purposes, the Utility cannot assure that the electricity will continue to be available for purchase in quantities sufficient to satisfy the residual net open position. Even with purchases of electricity in quantities sufficient to satisfy the residual net open position, the Utility would be exposed to wholesale electricity commodity price fluctuations and uncertain commercial and credit terms.

Conversely, the amount of energy provided by the DWR contracts likely will result in excess electricity during various periods, which the Utility will be required to attempt to sell on the open market. If the Utility is unable to sell this excess electricity on the open market under terms and conditions that would recover its costs, its financial condition or results of operations may be adversely affected.

Nuclear Fuel - The Utility has purchase agreements for nuclear fuel components and services for use in operating the DCPP. The Utility relies on large, well-established international producers for its long-term 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.

In January 2002, the U.S. International Trade Commission (ITC) imposed tariffs of up to 50 percent on imports from certain countries providing nuclear fuel. As of June 2003, the tariffs are still being imposed; however, the Court of International Trade in New York City is reviewing the ITC decision. The Utility's 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 be higher than those under previous contracts if these tariffs remain in place. As noted above, the CPUC is obligated to change retail electricity rates at any time that the Utility's forecasts indicate it will face an under-collection of electricity procurement costs, including the cost of nuclear fuel, in excess of 5 percent of its prior year's generation revenues, excluding amounts collected for the DWR. Additionally, changes in the cost of nuclear fuel purchases also may impact the amount of previously written-off purchased power and transition costs that the Utility is able to recover.

Utility Natural Gas Commodity Price Risk

Through 2003, the Core Procurement Incentive Mechanism (CPIM) determines how much of the cost of procuring natural gas for its customers may be included in the Utility's natural gas procurement rates. Under the CPIM, the Utility's procurement costs are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a range, or tolerance band, of 99 percent to 102 percent around the benchmark are considered reasonable and may be fully recovered in customer rates. Ratepayers and shareholders share the costs and savings outside the tolerance band.

In addition, the Utility has contracts for transportation capacity on various natural gas pipelines. A recent CPUC decision found that the Utility's acquisition of additional interstate transportation capacity was reasonable and that all interstate transportation capacity already held by the Utility also was reasonable. Pending the results of a rehearing granted by the CPUC in April 2003, a future decision would allocate the cost of the transportation capacity between customer groups, determine the date on which all transportation capacity costs held by the Utility prior to July 2002 would be recoverable, and modify the CPIM to reflect costs allocated to core customers. In a settlement with the ORA, the Utility and the ORA have proposed to the CPUC that costs be allocated to core ratepayers and that various changes be made to the CPIM. Changes to CPIM include changing the sharing percentages for costs that fall below the CPIM tolerance band to 75 percent to ratepayers and 25 percent to shareholde rs. Ratepayers and shareholders would continue to share equally costs that are above the CPIM tolerance band.

Under the Gas Accord, shareholders are at risk for revenues from the sale of capacity on the Utility's gas transmissions and storage facilities. Capacity is sold at competitive market-based rates, within a cost-of-service tariff framework. Based on the underlying tariffs, revenues generally are lower when throughput volumes are lower than expected or when the price spread narrows between the gas transportation system's two principal receipt points. In August 2002, the CPUC approved a settlement agreement between the Utility and other parties that provided for a one-year extension of the Utility's existing gas transmission and storage rates and terms and conditions of service through the end of 2003. (The Gas Accord originally was scheduled to expire on December 31, 2002.) For further discussion, see "Gas Accord II" in the "Regulatory Matters" section of this MD&A.

PG&E NEG Price Risk

PG&E NEG is exposed to price risk from its portfolio of proprietary trading contracts and its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, and various merchant plants currently in development and construction.

As described above, PG&E NEG has significantly reduced its energy trading operations and has transitioned its operations to retain only the limited capabilities necessary to ensure fuel procurement and power logistics for PG&E NEG's retained independent power plant operations and to serve USGenNE's needs. As of June 30, 2003, PG&E NEG had reduced the aggregate value of its trading portfolio by more than 70 percent of the aggregate value at December 31, 2002.

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 requires the selection of 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 PRM activities. PG&E Corporation and the Utility therefore use the historical data for calculating the expected price volatility of their portfolio's contractual positions to project th e 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 the gas portfolio, with the exception of storage positions and 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 electric 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 Utility is in the process of developing a value-at-risk model and other methodologies appropriate for risk measurement of its electric portfolio. PG&E NEG's value-at-risk model includes all commodity derivatives and other financial instruments over the entire length of the terms of the transactions in the trading and non-trading portfolios.

The following table illustrates the potential one-day unfavorable impact for price risk as measured by the value-at-risk model, based on a one-day holding period. A comparison of daily values-at-risk as of June 30, 2003, and as of December 31, 2002, is included in order to provide context around the one-day amounts.

			June 30,		December 31,
(in millions)			2003		2002
Utility
	Non-trading activities (1)		$	5	$	4
PG&E NEG
	Trading activities		8		8
	Non-trading activities:
	Non-trading contracts that receive mark-to-market accounting treatment (2)		3		3
	Non-trading contracts accounted for as hedges (3)		8		9
(1)		Includes the Utility's gas portfolio only.
(2)		Includes derivative power and fuel contracts that do not qualify as normal purchases and sales exceptions and do not qualify to be accounted for as cash flow hedges under Statement of Financial Accounting Standards (SFAS) No. 133.
(3)		Includes only the risk related to the derivative instruments that serve as hedges and does not include the related underlying hedged item. Any gain or loss on these derivative commodity instruments would be substantially offset by a corresponding gain or loss on the hedged commodity positions, which are not included.

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 proceedings.

The Utility's value-at-risk for non-trading activities has increased as of June 30, 2003, as compared to levels as of December 31, 2002, due to increases in gas prices and volatility. PG&E NEG's value-at-risk for non-trading activities has decreased as of June 30, 2003, as compared to levels as of December 31, 2002, due to contract terminations. As PG&E NEG continues to wind down its asset and proprietary trading positions, an increase in the spark spread or increases in commodity prices or volatility could cause value-at-risk levels in the asset portfolio to increase. See the discussion above in the "Liquidity and Financial Resources - PG&E NEG" section of this MD&A for further information regarding PG&E NEG's current financial situation and the July 8, 2003, PG&E NEG Chapter 11 filing.

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 working capital facilities, variable rate tax-exempt pollution control bonds, and other variable rate debt.

PG&E Corporation and the Utility may use the following interest rate hedging instruments to manage their interest rate exposures: swaps, caps, floors, swaptions, or forward contracts. Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At June 30, 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 approximately $17 million over the next year for PG&E Corporation and by an immaterial amount for the Utility, based on net variable rate debt, hedging derivatives, 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. On or before the effective date of the Settlement Plan, the Utility is expected to enter into interest rate hedges to reduce the impact to ratepayers resulting from possible increases in interest rates on the notes to be issued. The Utility filed a petition with the CPUC during the third quarter 2003, requesting authorization to enter into up to $7.4 billion of interest rate hedges that would apply to the debt issued under any plan of reorganization and to recover in the Utility's retail gas and electric rates all costs associated with the hedges without being subject to further review requirements. Such hedges will expose the Utility to decreases in interest rates. The Utility plans to petition the Bankruptcy Court for the authority to engage in thes e interest rate hedges in August 2003.

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.

PG&E Corporation and the Utility are exposed to such risk associated with foreign currency exchange variations related to Canadian-denominated purchase and swap agreements. PG&E Corporation and the Utility may use forwards, swaps, and options to hedge foreign currency exposure.

For the Utility, 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's customers and shareholders would share in the costs or savings outside of the tolerance band.

PG&E Corporation and the Utility use sensitivity analysis to measure their exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at June 30, 2003, a 10 percent devaluation of the Canadian dollar would be immaterial to PG&E Corporation's and the Utility's Consolidated Financial Statements.

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; notes receivable included in Other Noncurrent Assets - Other; PRM assets; and Assets Held For Sale on the Consolidated Balance Sheets of PG&E Corporation and the Utility, as applicable. PG&E Corporation and the Utility conduct business primarily with customers or vendors, referred to as counterparties, in the energy industry. These counterparties include other 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 PG&E Corporation's and the Utility's overall exposure to credit risk because their counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions.

PG&E Corporation and the Utility manage their credit risk in accordance with the PG&E Corporation Risk Management Policy. This establishes processes for assigning credit limits to counterparties before entering into agreements with significant exposure to PG&E Corporation and the Utility. These processes include an evaluation of a potential counterparty's financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually.

Credit exposure is calculated daily, and in the event that exposure exceeds the established limits, PG&E Corporation and the Utility take immediate action to reduce the exposure, or obtain additional collateral, or both. Further, PG&E Corporation and the Utility rely 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.

PG&E Corporation and the Utility calculate 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 period ended June 30, 2003, PG&E Corporation's credit risk decreased, as compared to December 31, 2002, primarily due to contract terminations with PG&E NEG counterparties. During the period ended June 30, 2003, the Utility's credit risk decreased, as compared to December 31, 2002, primarily due to the receipt of payment from a previously terminated contract with a counterparty.

During the three- and six-month periods ended June 30, 2003, PG&E Corporation and the Utility recognized no losses due to the contract defaults or bankruptcies of counterparties.

At June 30, 2003, PG&E Corporation had no single counterparty that represented greater than 10 percent of PG&E Corporation's net credit exposure. At June 30, 2003, the Utility had one investment grade counterparty that represented 17 percent of the Utility's net credit exposure and one below-investment grade counterparty that represented 11 percent of the Utility's net credit exposure.

The schedule below summarizes PG&E Corporation's and the Utility's credit risk exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis), as well as PG&E Corporation's and the Utility's credit risk exposure to counterparties with a greater than 10 percent net credit exposure, at June 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
At June 30, 2003
PG&E Corporation		$	710	$	97	$	613		-	$	-
Utility (3)		220		55		165		2		46
At December 31, 2002
PG&E Corporation		$	1,165	$	195	$	970		-	$	-
Utility (3)		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, model, or credit reserves.
(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)	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 gas and electricity to millions of residential and small commercial customers.

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

Credit Quality (1)		Net Credit Exposure(2)		Percentage of Net Credit Exposure
(in millions)
At June 30, 2003
PG&E Corporation
Investment grade(3) (4)		$	363	59%
Noninvestment grade			120	20%
Not rated(4)			130	21%
Total		$	613	100%
Utility
Investment grade(3) (4)		$	101	61%
Noninvestment grade			64	39%
Not rated(4)			-	-
Total		$	165	100%
At December 31, 2002
PG&E Corporation
Investment grade(3) (4)		$	700	72%
Noninvestment grade			205	21%
Not rated(4)			65	7%
Total		$	970	100%
Utility
Investment grade(3) (4)		$	111	63%
Noninvestment grade			64	37%
Not rated(4)			-	-
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.
(4)	Most counterparties with no ratings are governmental authorities that are not rated through publicly available information, but which PG&E Corporation has assessed as equivalent to investment grade based upon an internal assessment of credit quality. These are designated as "investment grade" in the above. Other counterparties with no rating obtainable through publicly available information, are designated as "not rated" above, but are subject to an internal assessment of their credit quality and an internal credit rating designation.

PG&E Corporation has regional concentrations of credit exposure to counterparties that conduct business primarily throughout North America. 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 nonperformance from these customers is not considered likely. Reserves for uncollectible accounts receivable are provided for the potential loss from nonpayment by these customers based on historical experience. At June 30, 2003, the Utility had a net regional concentration of credit exposure totaling $165 million to counterparties that conduct business primarily throughout North America.

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. Certain of these estimates and assumptions are considered to be Critical Accounting Policies, due to their complexity, subjectivity, and uncertainty, along with their relevance to the financial performance of PG&E Corporation. 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.

Effective for the third quarter ended September 30, 2002, PG&E Corporation adopted the net method of recognizing realized gains and losses on energy trading contracts. Under the net method, revenues and expenses are netted and trading gains (or losses) are reflected in revenues on the Consolidated Statement of Operations, as opposed to reporting revenues and expenses under the previously used gross method.

PG&E Corporation and the Utility have derivative commodity contracts for the physical delivery of purchase and sale quantities such as natural gas and power 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 used generation-related revenues in excess of generation-related costs to recover approximately $2.0 billion, after-tax, in previously written-off under-collected purchased power and generation-related costs. The Utility has not provided reserves for potential refunds of these surcharges, nor would the surcharges be subject to refund under the proposed settlement agreement in the Utility's Chapter 11 proceeding. If the proposed 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 the DWR's 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 electric 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.

Factors that could affect the amount of pass-through revenues recorded by the Utility include whether the CPUC grants the DWR's requests for changes to the remittance formula contained in the servicing order and whether such changes would be retroactive to January 2001.

Depending on whether these changes or revisions 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 the "DWR Revenue Requirement and Operating Agreement" 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. These costs are later recovered through regulated rates. Regulatory liabilities are rate actions of a regulator that later will 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 June 30, 2003, PG&E Corporation reported regulatory assets of $2.1 billion, including current regulatory balancing accounts receivable, and regulatory liabilities of $1.2 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 June 30, 2003, the Utility's undiscounted environmental remediation liability was $302 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. PG&E NEG estimates that it may be required to spend up to approximately $678 million before insurance proceeds for environmental compliance at certain of its operating facilities through 2008. To date, PG&E NEG has spent approximately $13 million on environmental compliance. See Note 6 of the Notes to the Consolidated Financial Statements.

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 June 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

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 qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. Certain derivative contracts 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. 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.

The assessment of whether the contract qualifies for the normal purchase and sales exception, including whether the price adjustment is clearly and closely related to the asset being transacted, must be performed at the inception of the contract.

The implementation guidance in DIG C20 is effective for all existing and all future derivative contracts in the quarter beginning after July 10, 2003 (fourth quarter of 2003). Early application in the third quarter of 2003 is permitted. 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.

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

In May 2003, the FASB issued Statement No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150). The Statement addresses concerns of how to measure and classify in the statement of financial position 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.

The requirements of SFAS No. 150 are applicable to PG&E Corporation in the third quarter of 2003. The Statement will be implemented by reclassifying and remeasuring the Utility's $137 million of preferred stock with mandatory redemption provisions as a liability, at the present value of the redemption amount using the rate implicit in the contract at inception, without reclassifying prior dividends or accruals. The remeasurement and reclassification will not have an impact on earnings of PG&E Corporation or the Utility. The preferred stock with mandatory redemption provisions are to be measured subsequently at the amount of cash that would be paid under the conditions specified in the contract if settlement occurred at the reporting date. All amounts paid or to be paid to the holders of the financial instruments in excess of the initial measured amount are reflected in interest cost.

Determining Whether an Arrangement Contains a Lease

In May 2003, the 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. PG&E Corporation and the Utility currently are assessing the impact of EITF 01-8.

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 under what circumstances 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. PG&E Corporation and the Utility are currently evaluating the impacts, if any, of SFAS No. 149 on its Consolidated Financial Statements.

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 or arrangement with which it is involved. A "variable interest entity" is an entity that does not have sufficient equity investment at risk to permit the entity to finance its activities without additional subordinated financial support from other parties or an entity where equity investors lack 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 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 between February 1, 2003, and June 30, 2003. The consolidation requirements are applicable to PG&E Corporation in the third quarter of 2003. PG&E Corporation and the Utility are evaluating the impacts of FIN 46's initial recognition, measurement, and disclosure provisions on the Consolidated Financial Statements, and currently are unable to estimate variable interest entities that will be consolidated or disclosed when FIN 46 becomes effective.

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 $72 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 $68 million (including interest).

As a result of PG&E NEG 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. The resolution of these matters with the IRS is not expected to have a material adverse effect on PG&E Corporation's earnings. 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); PG&E NEG operated two facilities in 2001 and most of 2002. The aggregate amount claimed for these Section 29 credits was approximately $104 million. The results of these audits are not expected to have a material adver se effect on PG&E Corporation's earnings.

In 2003, PG&E Corporation increased its valuation allowance due to the continued uncertainty in realizing certain state deferred tax assets arising at PG&E NEG. Valuation allowances of $7 million for the three-month and $17 million for the six-month periods ended June 30, 2003, were recorded in continuing operations. Additional valuation allowances of $7 million were recorded in discontinued operations, and $5 million in accumulated other comprehensive loss for the six-month period ended June 30, 2003.

In addition to the above reserves, PG&E NEG recorded valuation allowances due to the uncertainty of realizing federal deferred tax assets. These valuation allowances were determined on a stand-alone basis. Valuation allowances of $56 million for the three-month and $122 million for the six-month periods ended June 30, 2003, were recorded in continuing operations, additional valuation allowances (benefits) of $(2) million and $35 million were recorded in discontinued operations, zero and $3 million were recorded in cumulative effect of changes in accounting principles, and $(4) million and $44 million were recorded accumulated other comprehensive loss. These PG&E NEG valuation allowances are eliminated in consolidation.

ADDITIONAL SECURITY MEASURES

Various federal regulatory agencies have issued guidance and the Nuclear Regulatory Commission (NRC) 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 gas transmission facilities. The current and pending guidance and the current orders may require additional capital investment and an increased level of operating costs. 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

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. Though the Utility has restarted the unit with the NRC's approval and the Utility believes it has technical justification to operate without further steam generator inspection until Unit 2's next scheduled refueling in the fall of 2004, it is possible that the Utility might be required by the NRC to take a mid-cycle steam generator inspection outage toward the end of 2003 or beginning of 2004. In addition, added 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. The Utility also now is planning to accelerate the replacement of steam generators, which is estimated to cost approximately $400 million for the two units combined, to 2008 and 2009 rather than 2009 as originally contemplated.

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 electric related costs. The Utility does not expect the system changes to have a significant impact on its financial position and results of operations.

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 o f $60 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. The Utility's defined benefit pension plan currently exceeds the minimum funding requirements of the Employee Retirement Income Security Act of 1974.

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 Audit Committee, are "audit committee financial experts" as defined by the SEC regulations, implementing Section 407 of the Sarbanes-Oxley Act of 2002. Each Board of Directors has determined that Mssrs. 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 engages in price risk management (PRM) activities for both trading and non-trading purposes. The Utility engages in PRM activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these PRM activities using forwards, 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 1: 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 June 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 (SEC) rules and forms.

There were no changes in internal controls over financial reporting that occurred during the quarter ended June 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 fiscal quarter, 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, and 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. However, PG&E Corporation has been informed that subsequent to the end of the second quarter, PG&E NEG has initiated appropriate actions and controls designed to prevent recurrence of the types of errors that led to the misclassifications.

In addition, PG&E NEG has been reviewing its second quarter presentation methods for netting certain trading and hedging revenues and expenses. PG&E NEG has adopted a net presentation approach for such transactions and has reflected this change in its second quarter results. For prior periods, PG&E NEG 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.

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

As previously disclosed in PG&E Corporation's and Pacific Gas and Electric Company's (Utility) combined 2002 Annual Report on Form 10-K, as amended, and combined quarterly report for the quarter ended March 31, 2003, as amended, in September 2001, PG&E Corporation and the Utility submitted a proposed plan of reorganization in the Utility's Chapter 11 proceeding pending in the U.S. Bankruptcy Court for the Northern District of California (that proposed to restructure the Utility's current business and to refinance the restructured businesses (the original plan of reorganization). After the Utility filed its original plan of reorganization, the CPUC, later joined by the Official Committee of Unsecured Creditors (OCC), submitted a competing proposed plan of reorganization with the Bankruptcy Court that does not provide for disaggregation of the Utility's businesses.

As previously reported in the Form 10-Q for the quarter ended March 31, 2003, the City of Palo Alto (Palo Alto), and the Northern California Power Agency (NCPA), among other parties, had filed an objection to the both proposed plans of reorganization. Palo Alto and NCPA asserted, among other allegations, that by virtue of the Utility's termination of a wholesale electric transmission contract between NCPA and the Utility, NCPA members, including Palo Alto, would now be subject to substantial charges from the California Independent System Operator Corporation (ISO). They claimed that damages associated with these increased ISO congestion charges, could exceed $1 billion. In early 2003, the Bankruptcy Court held a claims estimation hearing. On May 15, 2003, the Bankruptcy Court found that the objectors had failed to establish the likelihood of liability and that their damage estimates were too speculative, and assigned the claim no value for the purposes of evaluating the feasibility of both the Utili ty's and the CPUC's proposed plans of reorganization.

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. On June 20, 2003, the Bankruptcy Court issued an order continuing the stay of proceedings until further order by the Bankruptcy Court.

On June 19, 2003, PG&E Corporation, the Utility and the staff of the CPUC entered into a proposed settlement agreement that contemplates a new plan of reorganization (Settlement Plan) to supersede the competing plans of reorganization. Under the proposed settlement agreement, PG&E Corporation and the Utility would agree that they would no longer propose to disaggregate the historic businesses of the Utility as had been proposed in the original plan of reorganization. Instead the Utility would remain a vertically integrated utility subject to the CPUC's jurisdiction. The treatment of creditors under the proposed Settlement Plan would be consistent with that provided in the Utility's original plan of reorganization, except that those creditors that were to receive long-term notes to be issued by the limited liability companies contemplated under the original plan of reorganization or a combination of cash and long-term notes would be paid entirely in cash.

The proposed 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 settlement agreement must be executed by all parties on or before December 31, 2003. The CPUC will conduct public hearings before deciding whether or not to approve the proposed settlement agreement. On July 25, 2003, the Utility filed its testimony in support of the proposed settlement agreement. Testimony from the staff of the CPUC and the OCC was also filed on July 25, 2003. The CPUC is currently expected to vote on the proposed settlement agreement on December 18, 2003.

In addition, the Bankruptcy Court must confirm the Settlement Plan. While the CPUC is not a proponent, it would agree under the proposed settlement agreement to support the Settlement Plan. On July 31, 2003, the Bankruptcy Court approved the disclosure statement that will be used to solicit approval of the Settlement Plan from creditors entitled to vote on the Settlement Plan. On August 1, 2003, the Bankruptcy Court approved the Utility's and the OCC's proposed solicitation procedures and ordered that the solicitation period start on August 15 and end on September 29, 2003. The Bankruptcy Court has ordered that the confirmation hearing begin on November 3, 2003, and that all objections to the Settlement Plan be filed by September 2, 2003.

Under the proposed settlement agreement, 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 the proposed settlement agreement, the Settlement Plan or the confirmation order or other determination of the parties' rights under the proposed settlement agreement, the Settlement Plan or the confirmation order. The CPUC also would consent to the jurisdiction of any court or other tribunal or forum for such actions or proceedings including, but not limited to, the Bankruptcy Court.

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

The Utility and PG&E Corporation would agree that upon execution of the settlement agreement, they will request a stay of all proceedings before the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC), the Securities and Exchange Commission (SEC), and other regulatory agencies relating to approvals sought to implement the original plan of reorganization. On the effective date of the Settlement Plan or as soon thereafter as practicable, the Utility and PG&E Corporation would withdraw or abandon all applications for such regulatory approvals.

With respect to the application filed with the NRC for permission to transfer the NRC operating licenses held by the Utility for its Diablo Canyon nuclear power plant to one of the Utility's restructured businesses, as contemplated by the original plan of reorganization, the NRC issued its final order approving the transfers on May 27, 2003. The NRC's approval is effective but requires that the Utility satisfy several conditions prior to implementation of the transfers. These conditions include receipt of all other judicial and regulatory approvals necessary to support the transfers of the facilities and the transfer of the beneficial interest in the nuclear decommissioning funds for the plant. San Luis Obispo County has requested from the NRC a stay in the effectiveness of the approval, and that request remains pending before the NRC.

On July 1, 2003, NCPA filed in the U.S. Court of Appeals for the D.C. Circuit a petition for review of the NRC's May 27 transfer consent order, because the order reflects the NRC's earlier administrative decision of February 14, 2003, concluding that the agency would not transfer the existing antitrust license conditions to any new licensee. NCPA had previously filed a petition for judicial review of the February 14 antitrust decision of the NRC, and the matter remains pending before the Court. The Utility has intervened in both cases in support of the NRC's decision. NCPA, however, has filed a request in both cases to hold briefing and argument in abeyance pending resolution of the proposed settlement agreement, because the Settlement Plan would make the license transfers no longer necessary. On August 1, 2003, the U.S. Court of Appeals for the D.C. Circuit ordered that both cases be held in abeyance, pending further order of the Court. Similarly, on July 16, 2003, the Utility filed a request in the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) to hold in abeyance argument and decision in the matter of the San Luis Obispo County and CPUC petitions for review of the NRC's June 2002 decision denying San Luis Obispo County's and the CPUC's requests for a hearing with respect to the license transfer. Neither party has opposed that request.

In connection with the original plan of reorganization, on May 14, 2003, the Ninth Circuit heard oral argument on the appeal filed by the CPUC and other parties of the August 30, 2002, order issued by the District Court for the Northern District of California finding that the Bankruptcy Code expressly preempts "non-bankruptcy laws that would otherwise apply to bar, among other things, transactions necessary to implement the reorganization plan." The District Court order had reversed an earlier ruling by the Bankruptcy Court that found that bankruptcy law did not expressly preempt certain non-bankruptcy laws in connection with the original plan of reorganization, but that it could impliedly preempt non-bankruptcy laws in certain circumstances. The Utility and PG&E Corporation filed a notice on July 8, 2003, advising the Ninth Circuit of the proposed settlement agreement between PG&E Corporation, the Utility, and the staff of the CPUC and asking the Ninth Circuit on that basis to stay the appeal. The appellants have opposed the motion to stay the pending appeal, and the Utility and PG&E Corporation have filed further papers in support of its motion. On August 6, 2003, the Ninth Circuit denied the Utility's and PG&E Corporation's request to stay the appeal.

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 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 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.

PG&E NEG Chapter 11 Filing

On July 8, 2003, PG&E NEG filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code in the Bankruptcy Court for the District of Maryland, Greenbelt Division.   In addition, on July 8, 2003, each of the following indirect wholly owned subsidiaries of PG&E NEG filed a voluntary petition for relief under the provisions of Chapter 11 in the Bankruptcy Court: PG&E Energy Trading Holdings Corporation, PG&E Energy Trading-Power, L.P., PG&E Energy Trading - Gas Corporation, and PG&E ET Investments Corporation (collectively, the "ET Companies"), and, separately, USGen New England, Inc. (USGenNE).  On July 29, 2003, two other subsidiaries, Quantum Ventures and 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 PG&E NEG and other subsidiaries. Pursuant to Chapter 11, PG&E NEG 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. 

PG&E NEG also filed a proposed plan of reorganization with the Bankruptcy Court. If confirmed by the Bankruptcy Court and implemented, PG&E Corporation would no longer have any equity interest in PG&E NEG.

As a result of PG&E NEG's Chapter 11 filing and the resignation of PG&E Corporation's representatives who previously served on the PG&E NEG 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 PG&E NEG. For a discussion of the effect of PG&E NEG's Chapter 11 filing on PG&E Corporation's consolidated financial statements, see Note 3 of the Notes to the Consolidated Financial Statements.

PG&E Corporation does not expect that PG&E NEG's Chapter 11 filing will have a material adverse effect on its financial position or results of operations.

Pacific Gas and Electric Company v. California Public Utilities Commissioners

As previously disclosed, the Utility has filed a lawsuit in the District Court for the Northern District of California against the CPUC Commissioners, asking the court to declare that the federally tariffed wholesale power costs that the Utility had incurred to serve its customers are recoverable in retail rates under the federal filed rate doctrine (Filed Rate Case). On July 10, 2003, the Utility filed a motion to stay consideration by the Ninth Circuit of the CPUC's Eleventh Amendment and Johnson Act appeal in the Filed Rate Case. On July 11, 2003, the Ninth Circuit issued an order in the Filed Rate Case requiring the parties to submit a joint status report by August 1, 2003. The order specifies various issues that should be addressed in the joint status report, all relating to the proposed settlement agreement between PG&E Corporation, the Utility and the CPUC staff and the proposed Settlement Plan. On July 21, 2003, the CPUC filed a response to the Utility's motion in the Ninth Circuit, indica ting that it does not oppose the Utility's request for stay of the appeal. On August 1, 2003, the Utility and the CPUC filed their joint status report with the Ninth Circuit as ordered. The joint status report explained the provisions of the proposed settlement agreement pertaining to dismissal of the Filed Rate Case and stated that the Utility and the CPUC did not oppose staying or vacating submission of the appeal in the Filed Rate Case. On August 11, 2003, the Ninth Circuit issued an order staying proceedings in the Filed Rate Case, and ordered the parties to file a second status report by January 15, 2004.

For more information regarding this Filed Rate Case litigation, see "Item 3-Legal Proceedings" in PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended.

Neither PG&E Corporation nor the Utility can predict what the outcome of the Filed Rate Case litigation will be if pursued to its conclusion. However, under the terms of the proposed settlement agreement and the Settlement Plan, the Utility would dismiss with prejudice the Filed Rate Case on or as soon as practicable after the later of the effective date of the Settlement Plan or the date that CPUC approval of the proposed settlement agreement is no longer appealable.

Federal Securities Lawsuit

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 until October 29, 2003, to file a petition asking the U.S. Supreme Court to hear their appeal of the Ninth Circuit's July 2003 decision.

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.

PG&E Corporation believes the case is without merit and intends to present a vigorous defense. PG&E Corporation believes that the ultimate outcome of this litigation will not have a material adverse effect on PG&E Corporation's financial condition or results of operations.

In re: Natural Gas Royalties Qui Tam Litigation

For 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.

Moss Landing Power Plant

As previously disclosed, in December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water and organic debris from the intake, and that this procedure is not specified in the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). A settlement has been reached with the Central Coast Board, under which the Utility would pay a total of $5 million to be used for environmental projects. No civil penalties would be paid under the settlement. The Central Coast Board voted to accept the settlement in December 2002, and the Utility has obtained authorization from the Bankruptcy Court to enter into the final settlement agreement. The parties have signed the settlement agreement, which was incorporated into a consent decree entered in California Superior Court on May 9, 2003. The California Attorney General has filed a claim in the Utility's Chapter 11 case to preserve the Central Coast Board's claim. The Utility currently is seeking withdrawal of this claim.

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

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

Diablo Canyon Power Plant

The Utility's Diablo Canyon employs a "once-through" cooling water system, which is regulated under a NPDES permit issued by the Central Coast Board. This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above 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, Diablo Canyon'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 plant protects beneficial uses and that the intake technology reflects the "best technology available" under Section 316(b) of the Federal Clean Water Act. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement. On May 5, 2003, the Bankruptcy Court authorized the Utility to sign the final settlement agreement. 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 settlement to become effective, among other things, the Cen tral Coast Board must renew Diablo Canyon's NPDES permit. However, at its July 10, 2003, meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement accepted in March 2003 and the Central Coast Board requested its staff to develop additional information on possible mitigation measures.

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

Also, as previously disclosed in PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended, the California Department of Toxic Substances Control (DTSC), alleged that Diablo Canyon failed to maintain an adequate financial assurance mechanism to cover closure costs for its hazardous waste storage facility for several months during 2001, after the Utility's Chapter 11 filing, and sought $340,000 in civil penalties. The DTSC also alleged a variety of hazardous waste violations at Diablo Canyon and sought $24,330 in civil penalties.

In April 2003, the Utility signed a final settlement agreement with the DTSC, under which the Utility will pay approximately $165,000 in civil penalties and approximately $30,000 in costs. The Utility paid these amounts in May 2003. The California Attorney General had filed a claim in the Utility's Chapter 11 proceedings on behalf of DTSC, and the Utility currently is seeking withdrawal of those portions of the claim relating to financial assurance and hazardous waste matters.

The Utility believes that the ultimate outcome of these matters will not have a material adverse impact on its financial condition or results of operations.

Compressor Station Chromium Litigation

For 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 quarter ended March 31, 2003, as amended.

California Energy Trading Litigation

On July 17, 2003, Snohomish filed its opening brief in its appeal to the U.S. Court of Appeals for the Ninth Circuit.

On or about July 21, 2003, ET Power notified the courts in the Millar proceeding and the Snohomish proceeding of the automatic stay of litigation imposed by the bankruptcy laws.

For information regarding these matters, see PG&E Corporation's and the Utility's combined 2002 Annual Report on Form 10-K, as amended.

California Attorney General Complaint

On July 24, 2003, the District Court for the Northern District of California heard oral argument on the appeal and cross appeal of the Bankruptcy Court's remand order. 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 quarter ended March 31, 2003, as amended.

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

On July 24, 2003, the District Court for the Northern District of California heard oral argument on the appeal and cross appeal of the Bankruptcy Court's remand order. 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 quarter ended March 31, 2003, as amended.

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

On July 24, 2003, the District Court for the Northern District of California heard oral argument on the appeal and cross appeal of the Bankruptcy Court's remand order. 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 quarter ended March 31, 2003, as amended.

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

For information regarding this matter, see PG&E Corporation's and the Utility's combined 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 quarter ended March 31, 2003, as amended.

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 Bankruptcy Code, and non-payment of interest. As a result of these defaults, several of the letter of credit banks caused the acceleration and redemption of four series of pollution control bonds. All of these redemptions were funded by the letter 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 interest monthly. 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 petition for reorganization under Chapter 11 of the Bankruptcy Code 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 $155million.

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 petition for reorganization under Chapter 11 of the Bankruptcy Code 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.

PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.8 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling $2.5 billion, but this debt is non-recourse to PG&E NEG. For more information, please see Note 3 of the Notes to the Consolidated Financial Statements.

The Utility has authorized 75 million shares of First Preferred Stock ($25 par value) and 10 million shares of $100 First Preferred Stock ($100 par value), which may be issued as redeemable or non-redeemable preferred stock. (The Utility has not issued any $100 First Preferred Stock.) At June 30, 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 June 30, 2003. The 6.57 percent series and 6.30 percent series may be redeemed at the Utility's option beginning in 2002 and 2004, respectively, at par value plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of stock outstanding. At June 30, 2003, the redemption requirements for the Utility's redeemable preferred stock with mandatory redemption provisions are $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. Therefore, the $4 million sinking fund payment that was due on July 31, 2002, to redeem 150,000 shares of the 6.57 percent series was not made. The sinking fund payments are cumulative so that if on any given year's July 31 the sinking fund payment is not made, the remaining shares of the 6.57 percent series required to be redeemed must be redeemed before any shares of another series with a r equired sinking fund can be redeemed, 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 the regular 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 June 30, 2003, amounted to $63.2 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 six months ended June 30, 2003, was 1.87. Pacific Gas and Electric Company's earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 2003, was 1.80. 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

1. Exhibits:
   

10.1	Operating Agreement effective as April 1, 2003, between the State of California Department of Water Resources and Pacific Gas and Electric Company
10.2.1*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003
10.2.2*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003
10.2.3*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated April 18, 2003
10.2.4*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003
10.2.5*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003
10.3*	Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003
10.4*	Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003
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
18	Letter Regarding Change in Accounting Principles
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

*Management contract or compensatory agreement.

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

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

1. April 2, 2003		Item 5.	Other Events
			A.	Agreement with El Paso Corporation
			B.	FERC Decision to Increase Amount of Power Refunds
			C.	Pacific Gas and Electric Company Bankruptcy - Monthly Operating Report
		Item 7.	Financial Statements, Pro Forma Financial Information, and Exhibits
			Exhibit 99.1 - Pacific Gas and Electric Company Income Statement for the month ended February 28, 2003 and Balance Sheet dated February 28, 2003
2. April 2, 2003
PG&E Corporation and PG&E National Energy Group, Inc.
	Item 5.		Other Events
			A.	GenHoldings I, LLC
			B.	Options to Purchase Shares of PG&E NEG
	Item 7.		Financial Statements, Pro Forma Financial Information, and Exhibits
			Exhibit 99.1 - Waiver Letter dated as of March 21, 2003, among GenHoldings I, LLC, various lenders identified as the GenHoldings Lenders, the Administrative Agent, and acknowledged and agreed to by PG&E National Energy Group, Inc.
3. April 21, 2003	Item 5.		Other Events
			Pacific Gas and Electric Company's General Rate Case Proceeding
4. April 24, 2003	Item 5.		Other Events
			Pacific Gas and Electric Company Bankruptcy--Further Stay of Confirmation Trial
5. May 13, 2003	Item 12.		Results of Operations and Financial Condition (furnished to the SEC)
6. May 13, 2003	Item 9.		Regulation FD Disclosure (furnished to the SEC)
7. June 2, 2003	Item 9.		Regulation FD Disclosure (furnished to the SEC)
			Exhibit 99 - Pacific Gas and Electric Company Income Statement for the month ended April 30, 2003 and Balance Sheet dated April 30, 2003
5. June 16, 2003
PG&E Corporation and PG&E National Energy Group, Inc.
	Item 5.		Other Events
			Extension of Lake Road and La Paloma Transfer Dates
6. June 20, 2003	Item 5.		Other Events
			Proposed Settlement Agreement
7. June 27, 2003
PG&E Corporation and PG&E National Energy Group, Inc.
	Item 5.		Other Events
			Amended SEC filings
8. July 2, 2003
PG&E Corporation and PG&E National Energy Group, Inc.
	Item 5.		Other Events
			Extension of GenHoldings Transfer Date
			Settlement of DTE/Georgetown Tolling Dispute
	Item 7.		Financial Statements, ProForma 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
9. July 2, 2003
PG&E Corporation only
	Item 5.		Other Events
			Closing of Private Placement
	Item 7.		Financial Statements, ProForma 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 6 7/8 percent Senior Secured Note due 2008
10. July 2, 2003
PG&E Corporation only
	Item 5.		Other Events
			Press Release Regarding Closing of Private Placement
	Item 7.		Financial Statements, ProForma Financial Information, and Exhibits
			Exhibit 99 - Press release dated July 2, 2003
11. July 8, 2003
PG&E Corporation only
	Item 5.		Other Events
			PG&E National Energy Group, Inc. Bankruptcy
12. 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
13. August 14, 2003	Item 5.		Other Events
			Inability to file Form 10-Q by August 14, 2003
14. August 19, 2003	Item 12.		Results of Operation and Financial Condition (Furnished to SEC)
			Release of Second Quarter Earnings Results

(1) Unless otherwise noted, all reports were filed 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

BY:  /S/  CHRISTOPHER P. JOHNS

CHRISTOPHER P. JOHNS
Senior Vice President and Controller
(duly authorized officer and principal accounting officer)

PACIFIC GAS AND ELECTRIC COMPANY

BY:  /S/  DINYAR B. MISTRY

DINYAR B. MISTRY
Vice President and Controller
(duly authorized officer and principal accounting officer)

Dated:  August 19, 2003

EXHIBIT INDEX

Exhibit 10.1	Operating Agreement effective as April 1, 2003, between the State of California Department of Water Resources and Pacific Gas and Electric Company
Exhibit 10.2.1*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003
Exhibit 10.2.2*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003
Exhibit 10.2.3*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated April 18, 2003
Exhibit 10.2.4*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003
Exhibit 10.2.5*	Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003
Exhibit 10.3*	Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003
Exhibit 10.4*	Letter Regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003
Exhibit 11	Computation of Earnings Per Common Share
Exhibit 12.1	Computation of Earnings to Fixed Charges for Pacific Gas and Electric Company
Exhibit 12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
Exhibit 18	Letter Regarding Change in Accounting Principles
Exhibit 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
Exhibit 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
Exhibit 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
Exhibit 32.2**	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

*Management contract or compensatory agreement.

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

EX-10.1

Exhibit 10.1

Mailed 4/9/2003

Decision 03-04-029  April 3, 2003

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Rulemaking to Establish Policies and Cost Recovery Mechanisms for Generation Procurement and Renewable Resource Development. Rulemaking 01-10-024 (Filed October 25, 2001)

DECISION ON MOTIONS TO
APPROVE OPERATING AGREEMENTS

Decision Summary

          This decision grants Pacific Gas and Electric Company (PG&E's) and San Diego Gas and Electric Company (SDG&E's) requests for approval of Operating Agreements between PG&E and The California Department of Water Resources (DWR) and SDG&E and DWR, subject to certain modifications.  Appendices A and B of this decision contain "clean" copies of the approved Agreements for PG&E and SDG&E respectively.  PG&E and SDG&E may file advice letters with the executed copies of the modified Agreements within seven days.  The joint motion for a stay is denied.

Attachment AA
PG&E OPERATING AGREEMENT

Between

STATE OF CALIFORNIA
DEPARTMENT OF WATER RESOURCES

And

PACIFIC GAS AND ELECTRIC COMPANY

THIS AGREEMENT HAS BEEN FILED WITH AND APPROVED BY THE CALIFORNIA PUBLIC UTILITIES COMMISSION ("COMMISSION") FOR USE BETWEEN THE STATE OF CALIFORNIA DEPARTMENT OF WATER RESOURCES ("DWR") AND PACIFIC GAS AND ELECTRIC COMPANY ("UTILITY"). 

Execution Date: February   , 2003

Date of Commission Approval: 

Effective Date: 

OPERATING AGREEMENT

          This OPERATING AGREEMENT (this "Agreement") is between the State of California Department of Water Resources ("DWR"), acting solely under the authority and powers granted by AB1X, codified as Sections 80000 through 80270 of the Water Code, and not under its powers and responsibilities with respect to the State Water Resources Development System, and Pacific Gas and Electric Company, a California corporation ("Utility").  DWR and Utility are sometimes collectively referred to herein as the "Parties" and individually referred to as a "Party."  Unless otherwise noted, all capitalized terms shall have the meanings set forth in Article I of this Agreement.

R E C I T A L S

            WHEREAS, under the Act, DWR has entered into a number of long-term power purchase agreements for the purpose of providing the net short requirements to the retail ratepayers of the State's electrical corporations, including Utility; and 

            WHEREAS, the Contract Allocation Order of the Commission provides that such long-term power purchase agreements are to be operationally allocated among the State's electrical corporations, including Utility, solely for the purpose of causing the State's electrical corporations to perform certain specified functions on behalf of DWR, as DWR's limited agent, including dispatching, scheduling, billing and settlements functions, and to sell surplus energy, all as such functions relate to those certain power purchase agreements that are operationally allocated to each electrical corporation under the Contract Allocation Order; and

            WHEREAS, DWR wishes to provide for the performance of such functions under the Allocated Contracts by Utility on behalf of DWR in accordance with such long-term power purchase agreements as provided in this Agreement; and

            WHEREAS, consistent with the Contract Allocation Order, DWR will retain legal and financial obligations, together with ongoing responsibility for any other functions not explicitly provided in this Agreement to be performed by Utility, with respect to each of the Allocated Contracts and it is the intent of DWR and the Utility that the provisions of this Agreement will not constitute an "assignment" of the Allocated Contracts or Interim Contracts to Utility.

            WHEREAS, consistent with the Interim Contract Order of the Commission, DWR expects to enter into certain Interim Contracts prior to January 1, 2003 and DWR wishes to provide for the administration of such Interim Contracts by Utility.

            NOW, THEREFORE, in consideration of the mutual obligations of the Parties, the Parties agree as follows:

ARTICLE I

DEFINITIONS

            Section 1.01.  Definitions.  The following terms shall have the respective meanings in this Agreement: 

            The following terms, when used herein (and in the attachments hereto) with initial capitalization, shall have the meaning specified in this Section 1.01.  Certain additional terms are defined in the attachments hereto.  The singular shall include the plural and the masculine shall include the feminine and neuter, and vice versa.  "Includes" or "including" shall mean "including without limitation."  References to a section or attachment shall mean a section or attachment of this Agreement, as the case may be, unless the context requires otherwise, and reference to a given agreement or instrument shall be a reference to that agreement or instrument as modified, amended, supplemented or restated through the date as of which such reference is made (except as otherwise specifically provided herein).  Unless the context otherwise requires, references to Applicable Laws or Applicable Tariffs shall be deemed references to such laws or tariffs as they may be amended, replaced or restated from time to time.  References to the time of day shall be deemed references to such time as measured by prevailing Pacific Time.

           "Act" means Chapter 4 of Statutes of 2001 (Assembly Bill 1 of the First 2001-02 Extraordinary Session) of the State of California, as amended.

           "Agreement", means this Operating Agreement, together with all attached Schedules, Exhibits and Attachments, as such may be amended from time to time as evidenced by a written amendment executed by the Parties.

            "Allocated Contracts" means the long-term power purchase agreements operationally allocated to Utility under the Contract Allocation Order, without legal and financial assignment of such agreements to Utility, as provided in Schedule 1 attached hereto.

            "Allocated Power" means all power and energy, including the use of such power or energy as ancillary services, delivered or to be delivered under the Contracts. 

           "Applicable Commission Orders" means such rules, regulations, decisions, opinions or orders as the Commission may lawfully issue or promulgate from time to time, which relate to the subject matter of this Agreement.

           "Applicable Law" means the Act, Applicable Commission Orders and any other applicable statute, constitutional provision, rule, regulation, ordinance, order, decision or code of a Governmental Authority.

           "Applicable Tariffs" means Utility's tariffs, including all rules, rates, schedules and preliminary statements, governing electric energy service to Utility's customers in its service territory, as filed with and approved by the Commission and, if applicable, the Federal Energy Regulatory Commission.

            "Assign(s)" shall have the meaning set forth in Section 14.01.

           "Bonds" shall have the meaning set forth in the Rate Agreement.

           "Bond Charges" shall have the meaning set forth in the Rate Agreement.

           "Business Day" means the regular Monday through Friday weekdays that are customary working days, excluding holidays, as established by Applicable Tariffs.

           "Commission" means the California Public Utilities Commission.

           "Confidential Information" shall have the meaning set forth in Section 11.01(c).

           "Contracts" means the Allocated Contracts and the Interim Contracts.

           "Contract Allocation Order" means Decision 02-09-053 of the Commission, issued on September 19, 2002, as such Decision may be modified, revised, amended, supplemented or superseded from time to time by the Commission.

           "DWR Power" shall have the same meaning set forth in the Servicing Arrangement with such amendments to incorporate the Settlement Principles for Remittances and Surplus Revenues as provided in Exhibit C of this Agreement.

           "DWR Revenues" means those amounts required to be remitted to DWR by Utility in accordance with this Agreement and as further provided in the Servicing Arrangement.

           "Effective Date" means the effective date in accordance with Section 14.13, as such date is set forth on the cover page hereof.

           "Fund" means the Department of Water Resources Electric Power Fund established by Section 80200 of the California Water Code.

           "Good Utility Practice" means any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition.  Good Utility Practice does not require the optimum practice, method, or act to the exclusion of all others, but rather is intended to include acceptable practices, methods, or acts generally accepted in the Western Electric Coordinating Council region.

           "Governmental Authority" means any nation or government, any state or other political subdivision thereof, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to a government, including the Commission.

            "Governmental Program" means any program or directive established by Applicable Law which directly or indirectly affects the rights or obligations of the Parties under this Agreement and which obligates or authorizes DWR to make payments or give credits to customers or other third parties under such programs or directives.

           "ISO" means the California Independent System Operator Corporation.

           "Interim Contract Order" means Decision 02-08-071 of the Commission, issued on August 22, 2002, as such Decision may be amended or supplemented from time to time by the Commission.

           "Interim Contracts" mean the power purchase or exchange arrangements between DWR and various Suppliers entered into by DWR at the request of Utility and consistent with the Interim Contract Order, as listed in Schedule 2 attached hereto.

           "Order" means Decision 02-12-069 of the Commission, issued on December 19, 2002 as such decision may be amended or supplemented from time to time by the Commission.

           "Power Charges" shall have the meaning set forth in the Rate Agreement.

           "Priority Long Term Power Contract" shall have the meaning set forth in the Rate Agreement.

           "Rate Agreement" means the Rate Agreement between DWR and the Commission adopted by the Commission on February 21, 2002 in Decision 02‑02‑051.

           "Remittance" means a payment by Utility to DWR or its Assign(s) in accordance with the Servicing Arrangement.

            "Servicing Arrangement" means the Servicing Order as specified in Commission Decision 02-05-048, dated May 16, 2002.

            "Supplier" means those certain third parties who are supplying power pursuant to the Contracts.

            "Term" means term provided in Section 2.05 hereof.

            "URG" means utility-retained generation, including without limitation Utility's portfolio of generation resources and power purchase agreements prior to or after the Effective Date by Utility.

            Section 1.02.  Undefined Terms.  Capitalized terms not otherwise defined in Section 1.01 herein shall have the meanings set forth in the Act or the Servicing Arrangement.

ARTICLE II

OPERATIONAL ALLOCATION OF POWER PURCHASE AGREEMENTS;
MANAGEMENT OF THE CONTRACTS; ALLOCATED POWER; TERM

            Section 2.01.  Operational Allocation and Management of Power Purchase Agreements. On behalf of DWR, as its limited agent, Utility will perform certain day-to-day scheduling and dispatch functions, billing and settlements and surplus energy sales  and certain other tasks with respect to the Allocated Contracts and each Interim Contract, as more fully set forth in this Agreement. 

            As further provided in Contract Administration and Performance Test Monitoring Protocols set forth in Exhibit E, DWR will continue to monitor and audit the Supplier performance under the Contracts.  Upon development of a mutually agreeable plan, Utility will monitor the performance of Suppliers, as further provided in Exhibit E, subject, however, to DWR's right but not the obligation to audit and monitor all functions contemplated to be performed by Utility, all as further provided in this Agreement.

          Section 2.02. Standard of Contract Management.

          (a)  Utility agrees to perform the functions specified in this Agreement relating to the Allocated Contracts and prior to novation, and Interim Contracts in a commercially reasonable manner, exercising Good Utility Practice, and in a fashion reasonably designed to serve the overall best interests of retail electric customers.  Utility shall provide to DWR such information specifically provided in Exhibit F hereto to facilitate DWR's verification of Utility's compliance with this Section 2.02.

          (b)  To the extent requested by Utility, DWR shall provide evidence in Commission proceedings describing Utility's and DWR's performance, rights and obligations under this Agreement.

          (c)  DWR acknowledges the Commission's exclusive authority over whether the Utility has managed Allocated Power available under the Contracts in a just and reasonable manner and DWR and Utility agree that none of the provisions of this Agreement shall be interpreted to reduce, diminish, or otherwise limit the scope of any Commission authority or to give DWR any authority over such matters.

          (d)  The Utility acknowledges DWR's separate and independent right to evaluate and enforce Utility's commercial performance under this Agreement.

          (e)  Utility agrees to provide any information not otherwise required herein that is reasonably necessary to allow DWR to exercise its rights in subsection (d) above, provided that all such information shall be used solely for the purposes of exercising such rights.

          Section 2.03.  Good Faith.  Each Party hereby covenants that it shall perform its actions, obligations and duties in connection with this Agreement in good faith.

          Section 2.04.  DWR Power.  During the term of this Agreement, the electric power and energy, including but not limited to capacity, and output, or any of them from the Contracts delivered to retail end-use customers in Utility's service area shall constitute DWR Power for all purposes of the Servicing Arrangement.  Utility shall arrange for transmission service to accommodate surplus sales to the extent that transmission service is available and cost effective, all as further provided in Exhibit A. 

          Section 2.05.  Term.

          (a)  The Term of this Agreement shall commence on the Effective Date and shall terminate on the earlier of (a) the termination of the Servicing Arrangement, or (b) the termination of this Agreement by DWR upon ninety days' written notice to Utility, or (c) upon consultation with the Commission, the termination of the Agreement by DWR upon reasonable written notice to Utility no shorter than 30 days, or (d) pursuant to Article VII hereof, the termination of this Agreement by a non-defaulting Party after an Event of Default.  In addition, this Agreement will terminate as to each Contract that terminates in accordance with its terms.  DWR agrees to notify Utility as to the termination of each Contract as provided in Section 5.01(e) hereof.

          (b)  If an event occurs which has the effect of materially altering and materially adversely impacting the economic position of the Parties or either of them under this Agreement, then the affected Party may, by written notice, request that the Commission approve amendments to this Agreement or other arrangements incidental to this Agreement as necessary to preserve or restore the economic position under this Agreement held by the affected Party immediately prior to such event.  Such notice shall describe the event and shall include reasonable particulars as to the manner and extent to which the economic position of the Party giving notice has been adversely affected.  The parties shall use their reasonable efforts during a 180-day period following such notice to negotiate and effect such amendments following which, if such efforts are unsuccessful, upon DWR's sole discretion, DWR may terminate this Agreement immediately on notice.

ARTICLE III

LIMITED AGENCY / NO ASSIGNMENT

            Section 3.01.  Limited Agency.  Utility is hereby appointed as DWR's agent for the limited purposes set forth in this Agreement.  Utility shall not be deemed to be acting, and shall not hold itself out, as agent for DWR for any purpose other than those described in this Agreement.  Utility's duties and obligations shall be limited to those duties and obligations that are specified in this Agreement.

            Section 3.02.  No Assignment.  DWR shall remain legally and financially responsible for performance under each of the Contracts and shall retain liability to the counterparty for any failure of Utility to perform the functions referred to in this Agreement on behalf of DWR as its limited agent, under such Contracts in accordance with the terms thereof.  It is the intent of DWR and Utility that the provisions of this Agreement shall not constitute or result in an "assignment" of the Allocated Contracts in any respect.

ARTICLE IV

LIMITED DUTIES OF UTILITY

          Section 4.01. Limited Duties of Utility as to the Contracts.  During the Term of this Agreement, Utility shall:

          (a)  On behalf of DWR, as its limited agent, perform the day-to-day scheduling and dispatch functions, including day-ahead, hour-ahead and real time trading, scheduling transactions with all involved parties,  under the Allocated Contracts, perform billing and settlements functions and obtain relevant information for these functions such as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 hereto, all as more specifically provided in the Operating Protocols attached hereto as Exhibit A;

          (b)  On behalf of DWR, as its limited agent, enter into transactions for the purchase (or sale, as the case may be) of gas, gas transmission services, gas storage services and financial hedges, and perform the operational and administrative responsibilities for such purchases under gas tolling provisions under the Allocated Contracts, including the review of fuel plans and consideration of alternative fuel supply, all as more specifically provided in the Fuel Management Protocols attached hereto as Exhibit B;

          (c)  On behalf of DWR, as its limited agent, perform all necessary billing and settlement functions under the Allocated Contracts in accordance with the terms of the applicable Allocated Contracts.  In addition, perform all necessary billing and settlement functions related to DWR Revenues and remit DWR Revenues to DWR, consistent with the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C and the Servicing Arrangement;

          (d)  Assume financial responsibility for the ISO charges listed on Exhibit D attached hereto;

          (e)  On behalf of DWR, as its limited agent, upon development of a mutually agreeable plan, monitor the performance of Suppliers under the Allocated Contracts and undertake the administration of the Allocated Contracts, as more specifically provided in the Contract Administration and Performance Monitoring Protocols attached hereto as Exhibit E;

          (f)  Provide to DWR the necessary information required by DWR as more specifically provided in the DWR Data Requirements From Utility attached hereto as Exhibit F to facilitate DWR's continued performance of financial obligations related to Allocated Contracts and to facilitate DWR's verification, audit and monitoring related to the Allocated Contracts and reporting requirements set forth in Applicable Laws or agreements;

          (g)  At all times in performing its obligations under this Agreement (i) comply with the provisions of each of the Allocated Contracts, (ii) follow Good Utility Practice, and (iii) comply with all Applicable Laws and Applicable Commission Orders;

          (h)  Appoint a primary and secondary contact person, as set forth in Schedule 2 hereto, to coordinate the responsibilities listed in this Section 4.01; and

          (i)  On behalf of DWR, as its limited agent, make surplus energy sales as more specifically provided in this Agreement; and

          (j)  Prior to novation of the Interim Contracts by Utility in accordance with the terms of each such Interim Contract, comply with the provisions listed in paragraphs (a) through (i) of this Section 4.01, in each case substituting the defined term Interim Contract(s) for the term Allocated Contract(s).

Provided, however, in the event that DWR fails to provide or provides inaccurate information which results in Utility's non-compliance with its obligations under this Agreement, the resulting non-compliance by Utility shall not constitute an Event of Default under Section 7.01 hereof.

            Section 4.02.  Dispatch or Sale of Allocated Power.  Subject to any existing or new ISO tariff provisions that may affect the dispatch of such Contracts, Allocated Power from all Contracts shall be dispatched or sold, as the case may be, by Utility pursuant to the Operating Protocols attached hereto as Exhibit A. 

            Section 4.03.  DWR Revenues.  DWR Revenues shall be accounted and remitted to DWR consistent with the principles provided in the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C and the provisions of the Servicing Arrangement.  Unless otherwise specifically provided in this Agreement, Utility will not be required at any time to advance or pay any of its own funds in the fulfillment of its responsibilities under this Agreement.

            Section 4.04.  Ownership of Allocated Power.  Notwithstanding any other provision herein, and in accordance with the Act and Section 80110 of the California Water Code, Utility and DWR agree that DWR shall retain title to all Allocated Power, including DWR Power.  In accordance with the Act and Section 80104 of the California Water Code, upon the delivery of Allocated Power to Utility's customers, those customers shall be deemed to have purchased that power from DWR, and payment for such sale shall be a direct obligation of such customer to DWR.  In addition, Utility and DWR agree that DWR shall retain title to any surplus Allocated Power sold by Utility as limited agent to DWR as provided in this Agreement. 

ARTICLE V

DUTIES OF DWR

          Section 5.01. Duties of DWR.  Consistent with the Contract Allocation Order, during the Term of this Agreement, DWR shall:

          (a)  Remain legally and financially responsible under each of the Contracts and cooperate with Utility in the transition from DWR to Utility the performance of the functions provided in this Agreement;

          (b)  Assume legal and financial responsibilities and enter into or facilitate Utility's entering into transactions as DWR's limited agent, for the purchase (or sale, as the case may be) of gas, gas transmission services, gas storage services and financial hedges, and timely consent to or approve the Utility's performance of the operational and administrative responsibilities for such purchases under gas tolling provisions under the Allocated Contracts, including the review of fuel plans and consideration of alternative fuel supply, all as more specifically provided in the Fuel Management Protocols attached hereto as Exhibit B;

          (c)  Pay invoices to the Suppliers and perform all necessary verification, audit and monitoring of the billing and settlement functions to be performed on DWR's behalf, as its limited agent, by Utility relating to the Contracts and prior to novation, the Interim Contracts.  In addition, perform all necessary verification, audit and monitoring of the billing and settlement functions to be performed on DWR's behalf, as its limited agent, by Utility related to DWR Revenues, consistent with the principles set forth in the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C;

          (d)  Until such time as a mutually agreed upon plan may be entered into with Utility and approved by the Commission, and no earlier than January 1, 2004, continue to monitor the performance of Suppliers and conduct certain contract administration duties under the Allocated Contracts, all as more specifically provided in the Contract Administration and Performance Monitoring Protocols attached hereto as Exhibit E.  In addition, continue to perform all other administrative functions related to Contracts not explicitly provided in this Agreement to be performed by Utility on behalf of DWR, as its limited agent;

          (e)  Upon the termination of any Contract, submit in writing to Utility appropriate Schedules and Attachments to Exhibit A amended to reflect the termination of any Contract.  Such amended Schedules and Attachments shall become effective only upon the effective date of the termination of such Contract.  Provided, however, rights or obligations of the Parties that arise or relate to Utility's performance of its duties under this Agreement in respect of any terminated Contract shall survive until the expiration of any such right or obligation;

          (f)  Appoint a primary and secondary contact person, as set forth in Schedule 3 hereto, to coordinate the responsibilities listed in this Section 5.01.

ARTICLE VI

SPECIAL CONTRACT TERMS

            Section 6.01.  Special Contract Terms.  In addition to the obligations set forth in this Agreement, Utility agrees to comply with the terms and provisions applicable to the Interim Contracts as set forth in Schedule 2 hereto.

ARTICLE VII

EVENTS OF DEFAULT

          Section 7.01. Events of Default. The following events shall constitute "Events of Default" under this Agreement:

           (a)  any material failure by a Party to pay any amount due and payable under this Agreement that continues unremedied for five (5) Business Days after the earlier of the day the defaulting Party receives written notice thereof from the non-defaulting Party; or

           (b)  any material failure by Utility to schedule and dispatch Contracts, consistent with the principles set forth in Exhibit A; or

           (c)  any failure (except as provided in (a) or (b)) by a Party to duly observe or perform in any material respect any other covenant or agreement of such Party set forth in this Agreement, which failure continues unremedied for a period of 15 calendar days after written notice of such failure has been given to such Party by the non-defaulting Party; or

           (d)  any material representation or warranty made by a Party shall prove to be false, misleading or incorrect in any material respect as of the date made; or

           (e)  an Event of Default (as defined under the Servicing Arrangement) shall have occurred and is continuing under the Servicing Arrangement.

           Section 7.02. Consequences of Utility Event of Default.  Upon any Event of Default by Utility, DWR may, in addition to exercising any other remedies available under this Agreement or under Applicable Law, (i) terminate this Agreement in whole or in part; and (ii) apply in an appropriate forum for sequestration and payment to DWR or its Assign(s) of DWR Revenues or for specific performance of the functions related to the Contracts to be performed by Utility on behalf of DWR, as its limited agent, as provided in this Agreement. 

            Section 7.03. Consequences of DWR Event of Default.  Upon an Event of Default by DWR, Utility may, in addition to exercising any other remedies available under this Agreement or under Applicable Law,  request that the Commission terminate this Agreement in whole or in part.

          Section 7.04. Remedies.  Subject to Article XIII of this Agreement, upon any Event of Default, the non-defaulting Party may exercise any other legal or equitable right or remedy that may be available to it under applicable law or under this Agreement. 

          Section 7.05. Remedies Cumulative.  Except as otherwise provided in this Agreement, all rights of termination, cancellation, or other remedies in this Agreement are cumulative.  Use of any remedy shall not preclude any other remedy available under this Agreement.

          Section 7.06. Waivers. None of the provisions of this Agreement shall be considered waived by either Party unless the Party against whom such waiver is claimed gives such waiver in writing.  The failure of either Party to insist in any one or more instances upon strict performance of any of the provisions of this Agreement or to take advantage of any of its rights hereunder shall not be construed as a waiver of any such provisions or the relinquishment of any such rights for the future, but the same shall continue and remain in full force and effect.  Waiver by either Party of any default by the other Party shall not be deemed a waiver of any other default.

ARTICLE VIII

PAYMENT OF FEES AND CHARGES

            Section 8.01.  Utility Fees and Charges.  As noted in the Contract Allocation Order, the details of the amount and recovery of administrative costs to Utility associated with the Contracts are expected to be considered in another Commission proceeding.  As such, the Parties agree that the administrative costs to Utility will be recovered pursuant to such Commission proceeding. Utility shall enter the cost of such fees and charges in its Purchased Electric Commodity Account, or its successor or another account designated by the Commission on a current basis, for recovery in retail rates subject to subsequent Commission review.

ARTICLE IX

REPRESENTATIONS AND WARRANTIES

          Section 9.01. Representations and Warranties.

           (a)  Each person executing this Agreement for the respective Parties expressly represents and warrants that he or she has authority to bind the Party on whose behalf he or she has executed this Agreement.

           (b)  Each Party represents and warrants that it has the full power and authority to execute and deliver this Agreement and to perform its terms, that execution, delivery and performance of this Agreement have been duly authorized by all necessary corporate or other action by such Party, and that this Agreement constitutes such Party's legal, valid and binding obligation, enforceable against such Party in accordance with its terms.

           (c)     DWR represents and warrants that all necessary and appropriate notices, inducements, undertakings, approvals, and consents have been obtained from each Supplier to the Contract allocated to Utility in order for Utility to undertake its duties set forth in this Agreement in a timely and appropriate fashion. 

ARTICLE X

LIMITATIONS ON LIABILITY

          Section 10.01. Consequential Damages. In no event will either Party be liable to the other Party for any indirect, special, exemplary, incidental, punitive, or consequential damages under any theory.  Nothing in this Section 10.01 shall limit either Party's rights as provided in Article VII above.

          Section 10.02. Limited Obligations of DWR. Any amounts payable by DWR under this Agreement shall be payable solely from moneys on deposit in the Department of Water Resources Electric Power Fund established pursuant to Section 80200 of the California Water Code (the "Fund"). 

          Section 10.03.  Sources of Payment; No Debt of State.  DWR's obligation to make payments hereunder shall be limited solely to the Fund and shall be payable as an operating expense of the Fund solely from Power Charges subject and subordinate to each Priority Long Term Power Contract in accordance with the priorities and limitations established with respect to the Fund's operating expenses in any indenture providing for the issuance of Bonds and in the Rate Agreement and in the Priority Long Term Power Contracts.  Any liability of DWR arising in connection with this Agreement or any claim based thereon or with respect thereto, including, but not limited to, any payment arising as the result of any breach or Event of Default under this Agreement, and any other payment obligation or liability of or judgment against DWR hereunder, shall be satisfied solely from the Fund.  NEITHER THE FULL FAITH AND CREDIT NOR THE TAXING POWER OF THE STATE OF CALIFORNIA ARE OR MAY BE PLEDGED FOR ANY PAYMENT UNDER THIS AGREEMENT. Revenues and assets of the State Water Resources Development System, and Bond Charges under the Rate Agreement, shall not be liable for or available to make any payments or satisfy any obligation arising under this Agreement.  If moneys on deposit in the Fund are insufficient to pay all amounts payable by DWR under this Agreement, or if DWR has reason to believe such funds may become insufficient to pay all amounts payable by DWR under this Agreement, DWR shall diligently pursue an increase to its revenue requirements as permitted under the Act from the appropriate Governmental Authority as soon as practicable.  To the extent DWR's obligations are "administrative costs," they will require annual appropriation by the legislature.

          Section 10.04. Cap on Liability.  In no event will Utility be liable to DWR for damages under this Agreement, including indemnification obligations, whether in contract, warranty, tort (including negligence), strict liability or otherwise (referred to as "Damages" for purposes of this Section), in an amount in excess of: 1) on an annual calendar year basis, $5 million plus ten percent of Damages in excess of $5 million and 2) for the entire term of this Agreement, $50 million in total payments of Damages to DWR.  For example, if Damages for an event are $100 million, Utility's total liability for this event would be $14.5 million ($5 million plus10% of $95 million) and that would be the full extent of Utility's liability for such Damages.  All Damages associated with an event will apply only to the annual limit in the first year in which Damages for that event were assessed.  For example, if Damages for an event were paid as follows: $15 million in year 1 and $10 million in year 2, the Utility would pay DWR $7 million ($5 million plus10% of $10 million for year 1 and 10% of $10 million for year 2).  In this example, the $1 million paid to DWR in year 2 (10% of $10 million) does not count against the year 2 $5 million calendar year threshold.  DWR hereby releases Utility from any liability for Damages in excess of the limitations on liability set forth in this Section 10.04, provided however, that this limitation on Utility liability shall not apply to the extent the liability is a result of Utility's gross negligence or willful misconduct.

ARTICLE XI

CONFIDENTIALITY

            Section 11.01.  Proprietary Information.

           (a)   Nothing in this Agreement shall affect Utility's obligations to observe any Applicable Law prohibiting the disclosure of Confidential Information regarding its customers.

           (b)   Nothing in this Agreement, and in particular nothing in Sections 11.01(e)(x) through 11.01(e)(z) of this Agreement, shall affect the rights of the Commission to obtain from Utility, pursuant to Applicable Law, information requested by the Commission, including Confidential Information provided by DWR to Utility. Applicable Law, and not this Agreement, will govern what information the Commission may disclose to third parties, subject to any confidentiality agreement between DWR and the Commission.

           (c)   The Parties acknowledge that each Party may acquire information and material that is the other Party's confidential, proprietary or trade secret information.  As used herein, "Confidential Information" means any and all technical, commercial, financial and customer information disclosed by one Party to the other (or obtained from one Party's inspection of the other Party's records or documents), including any patents, patent applications, copyrights, trade secrets and proprietary information, techniques, sketches, drawings, maps, reports, specifications, designs, records, data, models, inventions, know-how, processes, apparati, equipment, algorithms, software programs, software source documents, object code, source code, and information related to the current, future and proposed products and services of each of the Parties, and includes, without limitation, the Parties' respective information concerning research, experimental work, development, design details and specifications, engineering, financial information, procurement requirements, purchasing, manufacturing, business forecasts, sales and merchandising, and marketing plans and information.  In all cases, Confidential Information includes proprietary or confidential information of any third party disclosing such information to either Party in the course of such third party's business or relationship with such Party.  Utility's Confidential Information also includes any and all lists of customers, and any and all information about customers, both individually and aggregated, including but not limited to customers' names, street addresses of customer residences and/or facilities, email addresses, identification numbers, Utility account numbers and passwords, payment histories, energy usage, rate schedule history, allocation of energy uses among customer residences and/or facilities, and usage of DWR Power.  All Confidential Information disclosed by the disclosing Party ("Discloser") will be considered Confidential Information by the receiving Party ("Recipient") if identified as confidential and received from Discloser.

           (d)   Each Party agrees to take all steps reasonably necessary to hold in trust and confidence the other Party's Confidential Information.  Without limiting the generality of the immediately preceding sentence, each Party agrees (i) to hold the other Party's Confidential Information in strict confidence, not to disclose it to third parties or to use it in any way, commercially or otherwise, other than as permitted under this Agreement; and (ii) to limit the disclosure of the Confidential Information to those of its employees, agents or directly related subcontractors with a need to know who have been advised of the confidential nature thereof and who have acknowledged their express obligation to maintain such confidentiality.  DWR shall not disclose Confidential Information to employees, agents or subcontractors that are in any respect responsible for power marketing or trading activities associated with the State Water Resources Development System.

           (e)   The foregoing two paragraphs will not apply to any item of Confidential Information if:  (i) it has been published or is otherwise readily available to the public other than by a breach of this Agreement; (ii) it has been rightfully received by Recipient from a third party without breach of confidentiality obligations of such third party and outside the context of the provision of services under this Agreement; (iii) it has been independently developed by Recipient personnel having no access to the Confidential Information; (iv) it was known to Recipient prior to its first receipt from Discloser, or (v) it has been summarized, processed and incorporated for incorporation into reports, discussions, statements or any other further work product.   In addition, Recipient may disclose Confidential Information if and to the extent required by law or a Governmental Authority, provided that (x) Recipient shall give Discloser a reasonable opportunity to review and object to the disclosure of such Confidential Information, (y) Discloser may seek a protective order or confidential treatment of such Confidential Information, and (z) Recipient shall make commercially reasonable efforts to cooperate with Discloser in seeking such protective order or confidential treatment.  Discloser shall pay Recipient its reasonable costs of cooperating.

          Section 11.02.  No License.  Nothing contained in this Agreement shall be construed as granting to a Party a license, either express or implied, under any patent, copyright, trademark, service mark, trade dress or other intellectual property right, or to any Confidential Information now or hereafter owned, obtained, controlled by, or which is or may be licensable by, the other Party.

          Section 11.03.  Survival of Provisions.  The provisions of this Article XI shall survive the termination of this Agreement.

ARTICLE XII

RECORDS AND AUDIT RIGHTS

          Section 12.01.  Records.  Utility shall maintain accurate records and accounts relating to the Contracts in sufficient detail to permit DWR to audit and monitor the functions to be performed by Utility on behalf of DWR, as its limited agent, under this Agreement.  In addition, Utility shall maintain accurate records and accounts relating to DWR Revenues to be remitted by Utility to DWR, consistent with the Settlement Principles for Remittances and Surplus Revenues set forth in Exhibit C hereto.  Utility shall provide to DWR and its Assign(s) access to such records.  Access shall be afforded without charge, upon reasonable request made pursuant to Section 12.02.  Access shall be afforded only during Business Hours and in such a manner so as not to interfere unreasonably with Utility's normal operations.  Utility shall not treat DWR Revenues as income or assets of Utility or any affiliate for any tax, financial reporting or regulatory purposes, and the financial books or records of Utility and affiliates shall be maintained in a manner consistent with the absolute ownership of DWR Revenues by DWR and Utility's holding of DWR Revenues in trust for DWR (whether or not held together with other monies).

          Section 12.02.  Audit Rights. 

          (a)   Upon 30 calendar days' prior written notice, DWR may request an audit, conducted by DWR or its agents (at DWR's expense), of Utility's records and procedures, which shall be limited to records and procedures containing information bearing upon Utility's performance of its obligations under this Agreement.  The audit shall be conducted during Business Hours without interference with Utility's normal operations, and in compliance with Utility's security procedures.

           (b)   As provided in the Act, the State of California Bureau of State Audits (the "Bureau") shall conduct a financial and performance audit of DWR's implementation of Division 27 (commencing with Section 80000) of the California Water Code, and the Bureau shall issue a final report on or before March 31, 2003.  In addition, as provided in Section 8546.7 of the California Government Code, Utility agrees that, pursuant to this Section 12.02, DWR or the State of California Department of General Services, the Bureau, or their designated representative ("DWR's Agent") shall have the right to review and to copy (at DWR's expense) any non-confidential records and supporting documentation pertaining to the performance of this Agreement and to conduct an on-site review of any Confidential Information pursuant to Section 12.03 hereof.  Utility agrees to maintain such records for such possible audit for three years after final Remittance to DWR.  Utility agrees to allow such auditor(s) access to such records during Business Hours and to allow interviews of any employees who might reasonably have information related to such records.  Further, Utility agrees to include a similar right for DWR or DWR's Agent to audit records and interview staff in any contract between Utility and a subcontractor directly related to performance of this Agreement.

          Section 12.03.  Confidentiality.  Materials reviewed by either Party or its agents in the course of an audit may contain Confidential Information subject to Article XI above.  The use of all materials provided to DWR or Utility or their agents, as the case may be pursuant to this Article XII, shall comply with the provisions in Article XI and shall be limited to use in conjunction with the conduct of the audit and preparation of a report for appropriate distribution of the results of the audit consistent with Applicable Law.

          Section 12.04.  Annual Certifications.  At least annually, and in no event later than the tenth Business Day after the end of the calendar year, Utility shall deliver to DWR a certificate of an authorized representative certifying that to the best of such representative's knowledge, after a review of Utility performance under this Agreement, Utility has fulfilled its obligations under this Agreement in all material respects and is in compliance herewith in all material respects.

          Section 12.05.  Additional Applicable Laws.  Each Party shall make an effort to promptly notify the other Party in writing to the extent such Party becomes aware of any new Applicable Laws or changes (or proposed changes) in Applicable Tariffs hereafter enacted, adopted or promulgated that may have a material adverse effect on either Party's ability to perform its duties under this Agreement.  A Party's failure to so notify the other Party pursuant to this Section 12.05 will not constitute a material breach of this Agreement, and will not give rise to any right to terminate this Agreement or cause either Party to incur any liability to the other Party or any third party.

          Section 12.06.  Other Information.  Upon the reasonable request of DWR or its Assign(s), Utility shall provide to DWR or its Assign(s) any public financial information in respect of Utility applicable to services provided by Utility under this Agreement, to the extent such information is reasonably available to Utility, which (i) is reasonably necessary and permitted by Applicable Law to monitor the performance by Utility hereunder, or (ii) otherwise relates to the exercise of DWR's rights or the discharge of DWR's duties under this Agreement or any Applicable Law.  In particular, but without limiting the foregoing, Utility shall provide to DWR any such information that is necessary or useful to calculate DWR's revenue requirements (as described in Sections 80110 and 80134 of the California Water Code).

          Section 12.07.  Data and Information Retention.  All data and information associated with the provision and receipt of services pursuant to this Agreement shall be maintained for the greater of (a) the retention time required by Applicable Law or Applicable Tariffs for maintaining such information, or (b) three (3) years.

ARTICLE XIII

DISPUTE RESOLUTION

          Section 13.01.  Dispute Resolution.  Should any dispute arise between the Parties or should any dispute between the Parties arise from the exercise of either Party's audit rights contained in Section 12.02 hereof, the Parties shall remit any undisputed amounts and agree to enter into good faith negotiations as soon as practicable to resolve such disputes within (10) Business Days so as to resolve such disputes, as appropriate, within the timeframes provided under this Agreement, or as soon as possible thereafter.  For any disputed Remittances, if such resolution cannot be made before the remittance date, Utility shall remit the undisputed portion to DWR.  In addition, the disputed portion of the Remittances shall be deposited into an escrow account held by a qualified, independent escrow holder.  Upon resolution of such disputes, the Party that escrowed the disputed amount shall reimburse the other Party from the escrow account as necessary.

          Section 13.02.  ISO Settlements Disputes.  Utility shall review, validate and verify all ISO charges/credits contained on all ISO settlement statements, including any charges/credits resulting from functions related to the Contracts to be performed by Utility as provided in this Agreement.  Utility shall inform DWR of any discrepancies and shall dispute any such discrepancies with the ISO in accordance with the ISO's tariff and protocols.  Except as provided in Section 13.03, if any ISO charge type settlement amount appearing on a Preliminary or Final Settlement Statement (as defined in the ISO tariff) resulting or relating to the Utility's performance of functions related to the Contracts under this Agreement is in dispute, it shall be the responsibility of Utility, on behalf of DWR, as its limited agent, to seek resolution of said dispute through the ISO dispute resolution process as provided in the ISO's tariff. 

          For disputes affecting Utility's Remittances to DWR, including disputes on ISO charges to non-DWR parties that would affect Remittances to DWR, Utility shall provide to DWR: a) notification of submission of the dispute through the ISO dispute resolution process, identifying, among other items, the dispute type, quantity, price and allocation; b) a copy of the submitted dispute and all supporting data; and c) a copy of all ensuing documentation resulting from the ongoing dispute resolution process.  Utility shall track and validate all disputed ISO charges involving any financial responsibility of DWR.

          Section 13.03.  Supplier Invoice Disputes.  DWR shall continue to be responsible for all dispute resolution relating to Supplier invoices.  In addition, except as specifically provided in Exhibit E of this Agreement, all other contract administration functions shall remain DWR's responsibility. 

          Section 13.04.  Good-Faith Negotiations.  Should any dispute arise between the Parties relating to this Agreement, the Parties shall undertake good-faith negotiations to resolve such dispute.  If the Parties are unable to resolve such dispute through good-faith negotiations, either Party may submit a detailed written summary of the dispute to the other Party.   Upon such written presentation, each Party shall designate an executive with authority to resolve the matter in dispute.  If the Parties are unable to resolve such dispute within 30 days from the date that a detailed summary of such dispute is presented in writing to the other Party, then either Party may, at its sole discretion, submit the dispute to the Commission for final resolution. 

          Section 13.05.  Costs.  Each Party shall bear its own respective costs and attorney fees in connection with respect to any dispute resolution process undertaken by it pursuant to this Article.  Provided, however, DWR shall reimburse Utility all reasonably incurred costs, including, but not limited to, in-house and retained attorneys, consultants, witnesses, and arbitration costs, arising from or pertaining to all disputes relating to ISO charges/credits contained on all ISO settlement statements resulting from the operational, dispatch and administrative functions related to the Contracts performed by Utility on behalf of DWR, as its limited agent, pursuant to the standards set forth in Section 2.02 herein and consistent with the provisions of the ISO tariff, as may be amended from time to time, including disputes on ISO charges to non-DWR parties that would affect Remittances to DWR.  These costs shall be recorded and invoiced in the manner set forth in Section 8.01 hereof.

ARTICLE XIV

MISCELLANEOUS

          Section 14.01.  Assignment

           (a)  Except as provided in paragraphs (b) (c), (d) and (e) below, neither Party shall assign or otherwise dispose of this Agreement, its right, title or interest herein or any part hereof to any  entity, without the prior written consent of the other Party.  No assignment of this Agreement shall relieve the assigning Party of any of its obligations under this Agreement until such obligations have been assumed by the assignee. When duly assigned in accordance with this Section 14.01(a) and when accepted by the assignee, this Agreement shall be binding upon and shall inure to the benefit of the assignee.  Any assignment in violation of this Section 14.01 (a) shall be void.

           (b)  Utility acknowledges and agrees that DWR may assign or pledge its rights to receive performance hereunder to a trustee or another party ("Assign(s)") in order to secure DWR's obligations under its bonds (as that term is defined in the Act), and any such Assign shall be a third party beneficiary of this Agreement; provided, however, that this authority to assign or pledge rights to receive performance hereunder shall in no event extend to any person or entity that sells power or other goods or services to DWR.

           (c)  Any person (i) into which Utility may be merged or consolidated, (ii) which may result from any merger or consolidation to which Utility shall be a party or (iii) which may succeed to the properties and assets of Utility substantially as a whole, which person in any of the foregoing cases executes an agreement of assumption to perform every obligation of Utility hereunder, shall be the successor to Utility under this Agreement without further act on the part of any of the Parties to this Agreement; provided, however, that Utility shall have delivered to  DWR and its Assign(s) an opinion of counsel reasonably acceptable to DWR stating that such consolidation, merger or succession and such agreement of assumption complies with this Section 13.01(c) and that all of Utility's obligations hereunder have been validly assumed and are binding on any such successor or assign.

           (d)  Notwithstanding anything to the contrary herein, DWR's rights and obligations hereunder shall be transferred, without any action or consent of either Party hereto, to any entity created by the State legislature which is required under Applicable Law to assume the rights and obligations of DWR under Division 27 of the California Water Code.

           (e)  Notwithstanding anything to the contrary herein, Utility's rights and obligations under this Agreement may be assigned to the reorganized debtor under a plan of reorganization approved by the Bankruptcy Court for Utility without any action or consent of either Party hereto.

          Section 14.02.  Force Majeure.  Neither Party shall be liable for any delay or failure in performance of any part of this Agreement (including the obligation to remit money at the times specified herein) from any cause beyond its reasonable control, including but not limited to, unusually severe weather, flood, fire, lightning, epidemic, quarantine restriction, war, sabotage, act of a public enemy, earthquake, insurrection, riot, civil disturbance, strike, restraint by court order or Government Authority, or any combination of these causes, which by the exercise of due diligence and foresight such Party could not reasonably have been expected to avoid and which by the exercise of due diligence is unable to overcome. 

          Section 14.03.  Severability.  In the event that any one or more of the provisions of this Agreement shall for any reason be held to be unenforceable in any respect under applicable law, such unenforceability shall not affect any other provision of this Agreement, but this Agreement shall be construed as if such unenforceable provision or provisions had never been contained herein.

          Section 14.04.  Survival of Payment Obligations.  Upon termination of this Agreement, each Party shall remain liable to the other Party for all amounts owing under this Agreement.  Utility shall continue to collect and remit, pursuant to the terms of the Servicing Arrangement and the principles provided in the Settlement Principles for Remittances and Surplus Revenues provided in Exhibit C hereto and any DWR Charges billed to customers or any DWR Surplus Energy Sales Revenues attributable to sales entered into before the effective date of termination of the Servicing Arrangement. 

          Section 14.05.  Third-Party Beneficiaries.  The provisions of this Agreement are exclusively for the benefit of the Parties and any permitted assignee of either Party and there are no third party beneficiaries under this Agreement.

          Section 14.06.  Governing Law.  This Agreement shall be interpreted, governed and construed under the laws of the State of California without regard to choice of law provisions.

          Section 14.07.  Multiple Counterparts.  This Agreement may be executed in multiple counterparts, each of which shall be an original.

          Section 14.08.  Section Headings.  Section and paragraph headings appearing in this Agreement are inserted for convenience only and shall not be construed as interpretations of text.

          Section 14.09.  Amendments.  No amendment, modification, or supplement to this Agreement shall be effective unless it is in writing and signed by the authorized representatives of both Parties and approved as required, and by reference incorporates this Agreement and identifies the specific portions that are amended, modified, or supplemented or indicates that the material is new.  No oral understanding or agreement not incorporated in this Agreement is binding on either of the Parties.

          Section 14.10.  Amendment Upon Changed Circumstances.  The Parties acknowledge that compliance with any Commission decision, legislative action or other governmental action (whether issued before or after the Effective Date of this Agreement) affecting the operation of this Agreement, including but not limited to (i) dissolution of the ISO, (ii) changes in the ISO market structure, (iii) a decision regarding direct access currently pending before the Commission, (iv) the establishment of other Governmental Programs, or (v) a modification to the Contract Allocation Agreement may require that amendment(s) be made to this Agreement.  The Parties therefore agree that if either Party reasonably determines that such a decision or action would materially affect the services to be provided hereunder or the reasonable costs thereof, then upon the issuance of such decision or the approval of such action (unless and until it is stayed), the Parties will negotiate the amendment(s) to this Agreement that is (or are) appropriate in order to effectuate the required changes in services to be provided or the reimbursement thereof.  If the Parties are unable to reach agreement on such amendments within 60 days after the issuance of such decision or approval of such action, either Party may, in the exercise of its sole discretion, submit the disagreement to the Commission for proposed resolution.  Nothing herein shall preclude either Party from challenging the decision or action which such Party deems may adversely affect its interests in any appropriate forum of the Party's choosing.

          The Parties agree that, if the rating agencies request changes to this Agreement which the Parties reasonably determine are necessary and appropriate, the Parties will negotiate in good faith, but will be under no obligation to reach agreement or to ask the Commission to amend this Agreement to accommodate the rating agency requests and will cooperate in obtaining any required approvals of the Commission or other entities for such amendments.

          Section 14.11  Indemnification.

           (a)  Indemnification of DWR.  Utility (the "Indemnitor") shall at all times protect, indemnify, defend and hold harmless DWR, and its elected officials, appointed officers, employees, representatives, agents and contractors (each, an "Indemnified Party" or an "Indemnitee") from and against (and pay the full amount of) any and all claims (whether in tort, contract or otherwise), demands, expenses (including, without limitation, in-house and retained attorneys' fees) and liabilities for losses, damage, injury and liability of every kind and nature and however caused, and taxes (of any kind and by whomsoever imposed), to third parties arising from or in connection with (or alleged to arise from in connection with):  (1) any failure by Utility to perform its material obligations under this Agreement; (2) any material representation or warranty made by Utility shall prove to be false, misleading or incorrect in any material respect as of the date made; (3) the gross negligence or willful misconduct of Utility or any of its officers, directors, employees, agents, representatives, subcontractors or assignees in connection with this Agreement; and (4) any violation of or failure by Utility or Indemnitor to comply with any Applicable Commission Orders or Applicable Law; provided, however, that the foregoing indemnifications and protections shall not extend to any losses arising from gross negligence or willful misconduct of any Indemnified Party.

           (b)  Obligation of Utility. Consistent with the Contract Allocation Order, Utility shall not, in acting as limited agent of DWR hereunder be required to perform any obligations of any Supplier under any Allocated Contract or to make any payments on behalf of such Supplier or as the result of the failure of such Supplier to perform under any Allocated Contract.

           (c)  Indemnification of Utility. To the extent permitted by law, DWR ("Indemnitor") shall at all times protect, indemnify, defend and hold harmless Utility, and its officers, employees, representatives, agents and contractors (each, an "Indemnified Party" or "Indemnitee"), from and against (and pay the full amount of) any and all claims (whether in tort, contract or otherwise), demands, expenses (including, without limitation, in-house and retained attorneys' fees) and liabilities for losses, damage, injury and liability of every kind and nature and however caused, and taxes (of any kind and by whomsoever imposed), to third parties arising from or in connection with (or alleged to arise from on in connection with):  (1)  any failure by DWR to perform its material obligations under this Agreement or any Allocated Contract and, prior to novation, any Interim Contract; (2) any material representation or warranty made by DWR shall prove to be false, misleading or incorrect in any material respect as of the date made; (3) the gross negligence or willful misconduct of the DWR or any of its officers, directors or employees, agents, representatives, subcontractors or assignees in connection with this Agreement; (4) any action claiming Utility failed to perform any Supplier's obligations under a Contract; and (5) any violation of or failure by DWR or Indemnitor to comply with any Applicable Law; and provided, however, that the foregoing indemnifications and protections shall not extend to any losses arising from the gross negligence or willful misconduct of any Indemnified Party.

           (d)  Indemnification Procedures.  Indemnitee shall promptly give notice to Indemnitor of any claim or action to which it seeks indemnification from Indemnitor.  Indemnitor shall defend any such claim or action brought against it, and may also defend such claim or action on behalf of the Indemnitee (with counsel reasonably satisfactory to Indemnitor) unless there is any actual or potential conflict between Indemnitor and Indemnitee with respect to such claim or action.  If there is any actual or potential conflict between Indemnitor and Indemnitee with respect to such claim or action, Indemnitee shall have the opportunity to assume (at Indemnitor's expense) defense of any claim or action brought against Indemnitee by a third party; however, failure by Indemnitee to request defense of such claim or action by the Indemnitor shall not affect Indemnitee's right to indemnity under this Section 14.11.  In any action or claim involving Indemnitee, Indemnitor shall not settle or compromise any claim without the prior written consent of Indemnitee.

          Section 14.12.  Notices and Demands.  (a) Except as otherwise provided under this Agreement, all notices, demands, or requests pertaining to this Agreement shall be in writing and shall be deemed to have been given (i) on the date delivered in person, (ii) on the date when sent by facsimile (with receipt confirmed by telephone by the intended recipient or his or her authorized representative) or electronic transmission (with receipt confirmed telephonically or electronically by the intended recipient or his or her authorized representative) or by special messenger, or (iii) 72 hours following delivery to a United States post office when sent by certified or registered United States mail postage prepaid, and addressed as set forth below:

Utility:	Pacific Gas and Electric Company
	245 Market Street, Room 1267
	San Francisco, CA 94105-1814

Attn:	Roy Kuga
	Lead Director of Gas and Electric Supply
	Telephone: (415) 973-3806
	Facsimile: (415) 973-0585
	Email: rmk4@pge.com

DWR:	State of California
	The Resources Agency
	Department of Water Resources
	California Energy Resources Scheduling Division
	3310 El Camino Avenue, Suite 120
	Sacramento, California  95821

Attn:	Peter S. Garris
	Deputy Director
	Telephone:  (916) 574-2733
	Facsimile:  (916) 574-0301
	Email:  pgarris@water.ca.gov

          (a)  Each Party  shall be entitled to specify as its proper address any other address in the United States, or specify any change to the above information, upon written notice to the other Party complying with this Section 14.12.

           (b) Each Party shall designate on Attachment A the person(s) to be contacted with respect to specific operational matters.  Each Party shall be entitled to specify any change to such person(s) upon written notice to the other Party complying with this Section 14.12.

          Section 14.13.  Approval.  This Agreement shall be effective upon the execution by both Parties and approval of such executed agreement by the Commission.  Except as expressly provided otherwise herein, neither Party may commence performance hereunder until such date.  Any delay in the commencement of performance hereunder as a consequence of waiting for such approval(s) shall not be a breach or default under this Agreement.

          Section 14.14.  Government Code and Public Contract Code Inapplicable.  DWR has determined, pursuant to Section 80014(b) of the California Water Code, that application of certain provisions of the Government Code and Public Contract Code applicable to State contracts, including but not limited to advertising and competitive bidding requirements and prompt payment requirements, would be detrimental to accomplishing the purposes of Division 27 (commencing with Section 80000) of the California Water Code and that such provisions and requirements are therefore not applicable to or incorporated in this Agreement.

          Section 14.15. Annual Review. The provisions of the Exhibits are subject to annual review by DWR and Utility to ensure their relevance and usefulness.  In the event that the Parties mutually agree that certain provisions of the Exhibits should be amended or supplemented, an amendment to the Exhibit should be executed and Utility shall submit to the Commission for approval.

          Section 14.16 Other Operating Agreement.  It is DWR's intent to have a consistent operating agreement with all three investor-owned utilities (IOUs).  Should DWR reach an operating agreement with another IOU relating to the subject matter of this Agreement, that in Utility's judgment is more favorable on the whole than this Agreement, Utility shall have the right to receive the same terms and conditions as such other IOU.  This provision specifically does not allow Utility to select particular portions or provisions of such other IOU's operating agreement.  In addition, if Utility elects to be subject to such other IOU's operating agreement's terms and conditions, Utility shall be subject to such other IOU's operating agreement with only such modifications agreed to by DWR as necessary to address operating differences between that other IOU and Utility.  Utility shall exercise the foregoing right within 60 days following Commission approval of such other operating agreement.

Schedule 1

ALLOCATED CONTRACTS

Schedule 2

INTERIM CONTRACTS

Schedule 3

REPRESENTATIVES AND CONTACTS

PG&E EXHIBIT A

OPERATING PROTOCOLS

EXHIBIT A

OPERATING PROTOCOLS

Pursuant to Section 4.01 of this Agreement, on behalf of DWR as its limited agent, Utility shall perform the day-to-day scheduling and dispatch functions, including day-ahead, hour-ahead and real-time trading, scheduling of transactions with all involved parties, making surplus energy sales and obtaining relevant information for these functions such as transmission availability and others, with respect to the Allocated Contracts set forth in Schedule 1 to the Agreement, and, prior to novation, the Interim Contracts set forth in Schedule 2, all as more specifically provided below and in compliance with the provisions of each of the Contracts:

I.            Resource Commitment and Dispatch.  Utility agrees to use good faith efforts to dispatch Allocated Contracts, and, prior to novation, Interim Contracts, based on the principle of "least cost dispatch" to retail customers, consistent with the Contract Allocation Order and other Applicable Commission Orders. Utility shall undertake these least cost dispatch functions both of the Contracts and its URG so as to minimize the cost of service to retail customers based on circumstances known or that reasonably could have been known by Utility at the time dispatch decisions are made.  DWR shall have no role in enforcement or review of Utility least cost dispatch under this Agreement and all issues of Utility compliance with least cost dispatch shall be within the sole review of the Commission.

          A.   Annual, Quarterly and Weekly Load and Resource Assessment Studies.  Utility shall provide to DWR copies of its annual and quarterly load and resource assessment studies.  Provided that Utility submits substantially the same information to the Commission, copies of the Commission submission will be simultaneously sent to DWR to satisfy requirements of this section.  In addition, Utility will provide a weekly commitment and dispatch plan for informational purposes to DWR in the same form that such plan is used internally.

          B.   Scheduling Protocols.

               1.  DWR is responsible for notifying the counter-party to each of the Allocated Contracts that scheduling under the Allocated Contracts will be performed by Utility before the first day that schedules are due to be submitted by Utility.  DWR is responsible for notifying Utility of any changes to the Allocated Contracts that it has negotiated, including changes to the scheduling terms.  DWR agrees to provide such notice as soon as possible following the negotiation of any changed provisions and in any case prior to the time that any changed provisions become effective.

               To the extent that any of the Interim Contracts are amended or modified by DWR or Utility, including changes to the scheduling terms, DWR and Utility agree to provide such notice to the other Party as soon as possible following the negotiation of any changed provisions and in any case prior to the time that any such changed provisions become effective.

               2.  Utility agrees to schedule Contracts in accordance with their terms and in accordance with the requirements of the Control Area operator or operators with whom the Contract must be scheduled to provide for power delivery.

II.             ISO Ancillary Service (AS) Market.  Among the Contracts are resources that are or may be qualified to be bid into the ISO's Ancillary Services ("AS") market or that Utility may use in its self-provision of AS.  Utility is authorized to develop protocols and procedures for the use of DWR resources for AS.  Utility shall, upon DWR's request, provide to DWR such information concerning Utility's intended use of DWR resources for AS as DWR may reasonably request for planning and revenue requirement purposes.

III.             Surplus Energy Sales and Energy Exchanges

          A.   Over-generation.  If the ISO announces an  over-generation situation Utility will  back down resources in accordance with the ISO tariff and  Good Utility Practice. In order to reduce the need for physical curtailment in over-generation situations, DWR and Utility shall develop pay for curtailment protocols and procedures that will enable Utility to instruct a must-take resource not to deliver energy under specified conditions. The costs and charges associated with mitigation of an over-generation situation shall be allocated among the Parties on a pro-rata basis consistent with the surplus sales allocation principles set forth in Exhibit C.

          B.   Energy Exchange Arrangements.  Existing non-DWR/CERS exchanges and those that might be transacted post-2002, will be considered URG exchanges. The accounting of energy necessary to support energy exchanges is addressed in Exhibit C.

          C.   Surplus Energy Sales Arrangement.  Utility shall on a monthly basis prepare a sales plan addressing all surplus sales, including without limitation sales to manage over-generation, contemplated by the Utility for review by DWR.  Such plan shall address sales of power from the combined portfolio of URG resources and Allocated Contracts, which will be administered by Utility on its own behalf and acting as DWR's limited agent. As specified in Section 2.02 of the Agreement, Utility shall pursue surplus sales in a fashion reasonably designed to serve the overall best interests of retail electric customers based on information known or could have been known by Utility at the time.  Utility agrees to include sufficient details in the sales plans to allow DWR to satisfy its financial management and reporting requirements. To the extent there is surplus power uncommitted to a forward energy surplus sales transaction, Utility shall be required to bid such surplus energy in the day-ahead, hour-ahead or real-time market.  Utility shall arrange for transmission service to accommodate surplus sales to the extent that transmission service is available and cost effective.  The costs of transmission service, ISO charges and the costs of firm transmission rights associated with such surplus energy sales transactions shall be treated in accordance with the Settlement Principles for Remittances and Surplus Revenues attached hereto as Exhibit C.  

IV.             Outage Coordination and Determination of Resource Availability of Contracts.  Utility shall communicate with the Scheduling Coordinator of each Contract to coordinate, approve, document and report planned Contract outages.  For those Contracts where resource availability affects capacity payments, Utility will use good faith efforts to verify supplier actual resource availability, and keep records of resource availability as reported by Supplier.  In addition, Utility shall document all outages (forced and planned) and notices of outages of DWR contract resources and provide such documents to DWR within five (5) business days after the end of each calendar month.  Interim Contracts Utility and DWR agree that the Attachments and data requirements associated with this Agreement will be updated as needed to incorporate the addition of new Interim Contracts entered into after the execution date of this Agreement.

PG&E EXHIBIT B

FUEL MANAGEMENT PROTOCOLS

EXHIBIT B

FUEL MANAGEMENT PROTOCOLS

Certain of the Contracts listed on Schedule 1 of this Agreement provide DWR the option of either (i) letting the Supplier provide the necessary natural gas for its generating units at an index-based price or agreed upon fixed price or (ii) DWR procuring the gas supply and causing such supply to be delivered to the Supplier under a tolling arrangement ("Fuel Option").  Certain of the Contracts with Fuel Option provide that DWR can decide on a monthly basis whether to procure the gas and others provide that the decision be made annually or semi-annually when DWR reviews the Supplier's proposed fuel plan.

The purpose of this Exhibit B is to describe the relationship which will exist between DWR and Utility and the specific responsibilities of each as they all relate to managing the natural gas provisions of the Contracts which include Fuel Options.  Specifically, this Exhibit B will address responsibilities for the following activities: (i) determining types and lengths of gas contracts, (ii) nominating deliveries, (iii) contracting for gas transportation and storage, (iv) managing imbalances, (v) reviewing, authorizing and making payment of gas invoices and (vi) determining and implementing hedge strategies, as appropriate. 

I.     Operating Relationship Between DWR and Utility

While DWR will retain legal and financial responsibility for gas and related services, Utility shall, as a limited agent acting for DWR, perform the administrative and operational activities, as further specified below, required to ensure adequate gas is supplied to Suppliers' generating units, consistent with the tolling provisions included in the Contracts.  The intent of this relationship is to provide Utility sufficient flexibility and authority to execute normal day-to-day activities associated with managing the fuel provisions of tolling Contracts and procurement of natural gas and related services, as a limited agent acting on behalf of DWR without direct involvement by DWR but in a manner consistent with Utility Gas Supply Plans which have been reviewed and approved by DWR and the Commission. 

II.     Fuel Activities

Consistent with the terms of the Contracts with Fuel Options, Utility shall have administrative and operational authority to act, as a limited agent, for fuel supply related activities, consistent with the following goals and guidelines whenever Utility has recommended, and DWR has reviewed and approved such recommendation that gas for a Contract with Fuel Option be caused to be supplied by Utility from a list of approved providers.

            Utility shall use reasonable commercial efforts to secure delivery of gas in a reliable manner and consistent with gas requirements for producing scheduled energy.

            Utility shall develop a portfolio of gas supply for the Contracts that contain Fuel Options and where Utility is to supply gas, acting as limited agent on behalf of DWR, consistent with the approved Utility Gas Supply Plans.  Such portfolio should be diversified in terms of price mechanism, period of performance, and gas suppliers.

            Utility shall develop a portfolio of supply which is reasonably priced relative to the market and in accordance with an approved Utility Gas Supply Plan.

III.     Review of Supplier Fuel Plans

In accordance with the terms of each of the Contracts with Fuel Options, Utility, acting as a limited agent on behalf of DWR, shall review each fuel plan prepared and submitted by the Supplier, and forwarded to the Utility by DWR, and determine whether to recommend (i) approval of the Supplier Fuel Plan and authorization for the Supplier to provide gas to its generating unit(s), or (ii) procurement and management of gas supplies to the generating unit(s) by Utility.  Utility, acting as a limited agent on behalf of DWR, shall advise DWR and the Commission on a timely basis of its recommendation regarding responsibility for supplying natural gas.  DWR shall, on a timely basis, review Utility's recommendation and either approve or identify requested changes.  Once approved, Utility shall advise the Supplier in accordance with the time requirements included in the appropriate Contract with Fuel Option.  In addition, for any Supplier Fuel Plans which have been implemented and are operative as of the Effective Date, and where DWR has previously elected to be responsible for gas supply, Utility may advise DWR that it would rather have Supplier provide the gas as of the Effective Date.  DWR shall coordinate with Utility and Supplier to revise such Supplier Fuel Plans, to the extent possible, prior to the Effective Date.  

IV.     Fuel Procurement Strategies

Under the Contracts with Fuel Option, upon Utility's recommendation, and DWR's review and approval of such recommendation, Utility will be responsible for procuring the natural gas fuel from a list of approved gas providers. Utility shall, acting as the limited agent of DWR, have administrative and operational responsibility for determining its gas procurement strategies, including but not limited to (i) types of contracts, (ii) length of contracts, (iii) pricing terms, (iv) use of storage, (v) types of gas transportation, (vi) delivery point(s), (vii) whether and how to obtain gas price forecasts, (viii) if and what risk management tools are to be used, and (ix) how to maintain current market intelligence. 

Utility shall consolidate these strategies and submit them to DWR and the Commission as a "Utility Gas Supply Plan" by April 17, 2003 and, thereafter on a semi-annual basis during the Term.  Utility may also provide a copy of such Gas Supply Plan to DWR in advance of the filing with the Commission so as to be able to indicate DWR's approval of such plan.  Utility shall indicate in its Advice Letter filing to the Commission whether DWR has approved such plan as appropriate.  DWR shall also formally notify the Commission when it has approved such plan.

DWR and the Commission will review and approve the Utility Gas Supply Plans.  In the event of conflicting guidance between the Commission and DWR regarding various aspects of the Gas Supply Plan they respectively approve or reject, where DWR only approves a subset of what the Commission approves, then Utility shall operate within the sphere of DWR's approval.  If, however, the Commission explicitly rejects portions of the Gas Supply Plan that DWR would authorize, then Utility must operate within the limitations of the Commission's decision.  After a reasonable period of time operating within the framework of the Gas Supply Plans and the Commission's and DWR's respective approval and/or rejection of various pieces of the Gas Supply Plan, the Parties agree to meet and confer to determine whether the approval process may need to be revised in some manner, and Utility shall submit to Commission any such proposed revisions. Once approved, Utility may act within such Utility Gas Supply Plan without further DWR involvement, except as provided below.

V.     Gas Purchasing

Utility and DWR shall jointly determine a list of approved gas providers who can be used to supply gas under the Contracts with Fuel Options.  Master agreements intended to cover normal day-to-day volumes will then be executed with such approved providers.  While DWR will be the executing party under all DWR gas contracts, such agreements shall specifically authorize Utility to act for and on behalf of DWR, as a limited agent, in negotiating specific prices, quantities and delivery periods for specific purchases under such master agreements; provided however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR.  If Utility determines it would be beneficial to enter into any DWR gas contract which exceeds 3 months or have a total value exceeding $10 million, it shall negotiate such agreement(s) and submit them to DWR for advance approval and execution.  

VI.     Gas Transportation

Utility shall have responsibility for recommending to DWR which pipelines should transport gas if Utility, acting as limited agent on behalf of DWR is to supply gas  under a Contract with Fuel Option.  Following approval of or revision of Utility Gas Supply Plan, Utility shall negotiate firm and/or interruptible agreements with such pipelines, consistent with the Utility Gas Supply Plan and submit them to DWR for execution.  While DWR will be the executing party, such agreements with pipelines shall specifically authorize Utility to act for and on behalf of DWR in nominating gas deliveries, making imbalance trades and managing gas volumes transported under such agreements  provided, however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR.

VII.  Gas Scheduling

If permitted under the Allocated Contracts, the Utility shall have full administrative and operational responsibility for scheduling gas deliveries, whether to a specific generating plant or to storage for all gas contracts entered into by DWR or by Utility on DWR's behalf pursuant to this Exhibit B.  This function includes use of interstate and intrastate gas pipeline provider websites, confirming via telephone, and all other activities required to move gas from the designated delivery point, as determined by the Utility, to its destination, as determined by the Utility.

VIII.  Storage Capacity, Injections and Withdrawals

Utility shall have responsibility for devising plans for gas storage, if Utility, acting as limited agent on behalf of DWR,  is to supply gas under Contracts with Fuel Option from a list of approved providers.   Following approval of the Utility Gas Supply Plans, Utility shall negotiate firm and/or interruptible agreements with such storage service providers and submit them to DWR for execution.  While DWR will be the executing party with DWR remaining the principal under such contracts, such agreements with storage service providers shall specifically authorize Utility to act for and on behalf of DWR in nominating gas injections and withdrawals under such agreements; provided, however, on the earliest practicable date after the execution of this Agreement, DWR agrees to provide to Utility in writing and in advance of such negotiations any limits, including without limitation any terms, that may be required by DWR.  

IX.  Managing Gas Delivery/Usage Imbalances

For gas that it purchases and transports on behalf of DWR, Utility shall have full administrative and operational responsibility for monitoring and managing the daily status of gas usage vs. gas deliveries (i.e. gas imbalances).  In addition, to the extent that gas transportation providers issue operational flow orders or require adjustments in scheduled gas deliveries due to system constraints, Utility, acting as limited agent on behalf of DWR, shall be responsible for compliance with such orders.  Utility shall also be responsible for any penalties imposed by gas transportation providers for imbalances caused by Utility, due to its failure to exercise prudent gas management practices.

X.  Invoice Review, Approval and Payment

For natural gas, pipeline transportation and storage services it purchases in accordance with this Exhibit B, Utility, acting as limited agent on behalf of DWR, shall have responsibility for receiving invoices from gas, transportation and storage suppliers, reviewing them for accuracy, approving/rejecting invoices for payment and forwarding to DWR for payment; provided, however, on the earliest practicable date after the execution of this Agreement, DWR agrees to cause Utility to be authorized to receive such information from Suppliers.  Utility shall provide DWR sufficient documentation to verify payment of the invoices.

XI.     Forecasting

Utility shall be responsible for all gas price, demand and supply forecasts which Utility believes are consistent with any accepted gas supply responsibilities. 

XII.  Risk Management

Utility shall develop and include in its Gas Supply Plans, plans for the hedging of DWR Fuel Supply costs.  Final decisions relating to the use or non-use of financial tools such as futures, options and swaps to hedge future gas price exposure on any gas volumes not hedged by Utility under the Utility Gas Supply Plans shall be made and implemented by DWR.  Any such contracts executed by DWR on a "portfolio basis" should be utility-specific.

XIII.  Market Intelligence

Any and all efforts to obtain, analyze and utilize market intelligence for decision-making purposes shall be the responsibility of Utility. 

XIV.  Payment of Gas Costs

For natural gas, pipeline transportation, financial hedges and storage services that are purchased and provided by a Supplier under an approved Fuel Supply Plan, DWR shall pay such gas related costs as part of the invoice for commodity, product, or services submitted by the Supplier.  For natural gas, pipeline transportation and storage services provided under DWR contracts and administered by Utility on behalf of DWR, DWR shall pay invoices after they have been reviewed and approved for payment by Utility.

XV.  Allocation of Existing DWR Gas Contracts

DWR has entered into gas supply, transportation and storage contracts as provided in Attachment 1 to this Exhibit B that have expiration dates after the Effective Date of this Agreement.  The administrative and operational control of the contracts listed on Attachment 1 to this Exhibit B will become the responsibility of Utility.  This shall include (i) scheduling gas transportation, (ii) confirming gas deliveries, (iii) nominating gas withdrawals from and injections into storage, if applicable, (iv) and reviewing and approving invoices for payment.  When approved, invoices shall be transmitted to DWR for payment within 10 days of receipt of invoice from the gas supplier, gas storage or gas transportation provider.

XVI.  Pre-existing Financial Hedge Instruments

If DWR has entered into any financial hedge transactions that will remain operable after the Effective Date of this Agreement, DWR shall retain full administrative and operational control over such transactions.

PG&E EXHIBIT C

SETTLEMENT PRINCIPLES
FOR REMITTANCES AND
SURPLUS REVENUES

EXHIBIT C

SETTLEMENT PRINCIPLES FOR REMITTANCES AND SURPLUS REVENUES

This Exhibit C outlines the principles by which Utility will calculate revenues associated with surplus energy sales and DWR energy delivered to retail customers.  This Exhibit C also addresses the information that Utility will provide to DWR to support DWR payment of Contract invoices, and invoices from natural gas supplier(s) for fuel provided to service DWR Contracts where tolling options have been implemented. 

This Exhibit C works in conjunction with the applicable Servicing Arrangement with Utility for purposes of determining the remittance amounts by Utility, which serves as DWR's billing and collection agent.

In accordance with the Contract Allocation Order (*), this Exhibit C provides that:

·  Revenues will be allocated for both surplus sales and retail customer deliveries

·  Revenues will be allocated pro rata, based on dispatched quantities of energy

·  The principle of balancing least cost economic dispatch while maintaining reliability is reinforced through these revenue allocation protocols.

·  Surplus sales quantities will be calculated as the difference between Utility's Energy Delivery Obligations (EDO) and the combination of energy from URG and energy dispatched from the Contracts.

Where Utility's Energy Delivery Obligations is defined as: (1) Utility's retail load (**)which includes distribution losses, (2) all pump-back loads, (3) energy exchange transactions between Utility and counter parties, (4) existing wholesale obligations, and (5) transmission losses.

The principles herein, together with the applicable methods and calculations contained in the Servicing Arrangement, form a substantive component of the accounting protocols required to implement the Contract Allocation Order. This Exhibit should also be read in conjunction with Exhibit F ("Data Requirements").

Exhibit F may periodically be modified to include all data that DWR will require to verify the remittances of revenues as remittance or implementation protocols change.  Utility and DWR agree to modify Exhibit F to include or exclude information reasonable determined by DWR to allow DWR to verify Net DWR Retail Supply and the surplus remittances.

(*)   Contract Allocation Order is CPUC Decision (D.) 02-09-053.

(**)  PG&E retail load obligations per CPUC May 2002 Service Order (D.02-05-048) includes Western Area Power Administration (WAPA) load, although this load is not retail load.

I.           Utility Remittance to DWR

          Utility shall remit to DWR an Energy Payment for the delivery of Contract energy to  Utility retail customers (including the delivery or Contract energy to WAPA)  and a separate payment for DWR's share of Surplus Energy Sales Revenues.  The principles for the remittances to DWR of Surplus Energy Sales Revenue and Energy Payment are contained in Sections A and B of this Exhibit C, respectively.  The details for determination of the remittances to DWR by Utility are contained in the Servicing Arrangement.

          A.      Utility Remittance to DWR of Revenue from Surplus Energy Sales

           Surplus Energy and Revenues

          Surplus energy exists when dispatched supply from Utility portfolio and DWR Contracts exceeds Utility's Energy Delivery Obligations.  When such a condition exists, the revenues from the sale of surplus energy shall be shared between Utility and DWR.  Surplus sale revenues can occur either through a forward market sale or a delivery of the excess energy into the ISO real time market.  In addition to the sharing of surplus energy revenues, the quantity of any surplus energy shall likewise be shared between Utility and DWR, and used in the determination of the Hourly Percentage Factor described in Section I.(B).

          Surplus energy sales revenues shall be placed by Utility into a separate account (Surplus Sales Fund) to be held in trust and shall be disbursed by Utility to DWR in accordance with the pro-rata allocation principles in Exhibit C and consistent with the provisions of Attachment J of the Servicing Arrangement.  For surplus energy sales to third parties, Utility shall apply reasonable credit risk management criteria that is consistent with industry accepted credit standards.

           Surplus Energy Quantity

          The Surplus Energy quantity shall be determined by subtracting Utility's Energy Delivery Obligations from the sum of dispatched URG energy and dispatched DWR Supply.  URG energy shall include dispatched energy from URG, new Utility contracts and Utility market purchases with adjustments for Ancillary Services and ISO Instructed Energy as described under "Definitions and Adjustments."  DWR Supply shall include dispatched energy from DWR must take and dispatchable contracts plus adjustments described below.  

          DWR Surplus Energy quantity shall be the product of Surplus Energy quantity multiplied by the DWR Surplus Energy Percentage.  Utility Surplus Energy quantity shall be the remaining portion of Surplus Energy.  Both Utility and DWR Surplus Energy quantities shall be applied to the respective Party's energy supply quantities for determination of the Hourly Percentage Factor described in Section (B).

           Surplus Energy Sales Revenues

Surplus Energy Sales Revenues shall be shared between Utility and DWR in the same manner as Surplus Energy.  

           Forward Market Sale

DWR share of revenues from a forward market sale of surplus energy shall be the product of the net revenue multiplied by the DWR Surplus Energy Percentage.  Utility share of these revenues shall be net revenue less DWR share of net revenues.  Revenues from a forward market sale shall not be distributed to the Parties until after Utility receives the revenues from the sales and pays sale‑related charges.  Shared revenues from forward market sales shall be net of transmission costs and broker fees.

           ISO Real Time Market Sales

Revenues from delivery of surplus energy to the ISO real time market shall be determined from the product of positive load or supply deviation multiplied by the ISO real time market price.  These revenues will be netted against any ISO charges related to the load deviation, including a negative ISO price.  Load deviation is determined by subtracting the Utility metered supply from the Final Hour Ahead Supply Schedule, however only positive quantities, where schedule exceeds meter, reflect surplus conditions for revenue sharing. Supply deviation is determined by subtracting the Final Hour Ahead Supply Schedule (adjusted by real time instructions) from metered supply, however, only positive quantities, where meter exceeds the adjusted schedule, reflect surplus conditions for revenue sharing.

DWR share of revenues from delivery of surplus energy to ISO real time market shall be the product of the net revenues multiplied by the DWR Surplus Energy Percentage.  Utility share of these net revenues shall be the net revenue less DWR share of net revenues.  Revenues from delivery of surplus energy to the ISO real-time market shall not be distributed to the Parties until after the Utility received payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered.

           Over-generation Periods

During periods of over-generation condition as announced by the ISO, surplus sales may be made at very low, zero or even negative prices.  In such conditions, the surplus sale revenue calculations as described above still hold.  However it is recognized that the sales may result in little or no revenue.  Sales could even be done at a cost to the seller.  That seller could be Utility or the ISO selling in an "out-of-market" condition.  During these conditions, ISO-related charges assigned to Utility for such sales (e.g. – ISO selling out‑of‑market) are included in the surplus sales revenue as a cost.  During over-generation conditions there may be no market in which to sell surplus energy.  In that event, or in expectation of that event, Utility shall declare that no valid market exists for surplus energy and shall begin curtailing must-take resources in accordance with Utility's procedures for mitigating over-generation conditions.  Such mitigation measures shall be consistent with good utility practice, specifically hydroelectric facilities at spill or near-spill conditions and nuclear facilities scheduled by Utility are the last resources to be reduced in power output.

Over-generation for purposes of this Exhibit C is defined as the condition in which total supply exceeds total loads in the ISO control area.

Revenues or costs from delivery of surplus energy to the ISO real time market under an over-generation condition shall not be distributed to the Parties until after Utility receives payment for final monthly invoice from the ISO for the month in which the surplus energy was delivered.

           Calculation of Surplus Energy Percentage

DWR Surplus Energy Percentage shall be equal to the pro rata share of DWR Supply to the sum of Utility Supply and DWR Supply, expressed as follows:

DWR Surplus Energy Percentage = DWR Supply / (Utility Supply + DWR Supply) 

Where:

DWR Supply is total energy dispatched from DWR Contracts with adjustments for transmission losses, Ancillary Services and ISO Instructed Energy transactions described below.

Utility Supply is total energy dispatched from URG, new Utility contracts and Utility market purchases with adjustments for transmission losses, existing wholesale obligations, WAPA load, Ancillary Services and ISO Instructed Energy, exchange transactions, and ISO Uninstructed Energy as described below.

           Definitions and Adjustments

Certain energy and capacity transactions, which may be conducted by Utility in its normal course of business, may affect the Utility and DWR Supply quantities used in pro rata calculations.

           Exchanges are transactions where energy is delivered to a third party in one period and a similar, but not necessarily equal, amount of energy is returned by third party in a different period.  For the purposes of pro rata share calculation, exchanges use and supplement energy from the Utility Supply.

           Forward Sales are transactions where energy is sold in a forward market to balance supply with demand.  In general, for the purposes of remittance determination, forward sales are made using energy from the joint Utility/DWR portfolio.

           Ancillary Services are transactions where capacity from certain qualifying resources is sold to ISO for ancillary services rather than being used as energy to serve retail load.   Resources from both Utility portfolio and DWR Contracts may qualify for use as ancillary services.  Since the capacity used for ancillary services does not serve retail energy load, ancillary service capacity is not considered as a joint Utility/DWR portfolio transaction for the purpose of remittance determination.  If Utility or DWR Contract resource capacity is used for ancillary services, the capacity quantity will not be included in the supply quantity of the owning party for the purpose of pro rata share calculations, and owning party will retain all the revenues from the ancillary services as well as all associated transaction costs and ISO charges. 

           ISO Instructed Energy is a transaction where certain qualifying resources are able to sell energy from unused capacity to the ISO in the real time market.  The energy delivered from these resources is directed by the ISO in real time to balance supply and load imbalances on the grid.  Either Utility portfolio or DWR Contracts may contain resources that have ability to provide instructed energy to ISO.  Since instructed energy is resource specific and does not directly serve the retail load of any utility, instructed energy is not considered as a joint Utility/DWR portfolio transaction for the purpose of remittance determination.  If Utility or DWR Contract resources are dispatched as instructed energy, the energy quantity will not be included in the supply quantity of the owning party for the purpose of pro rata share calculations, and owning party will retain all the revenues from the instructed energy as well as all associated transaction costs and ISO charges.   

           ISO Uninstructed Energy is a transaction where energy is delivered or received from the ISO grid in the real time based on the actual consumption of retail load and actual deliveries of supply resources.   

           Uninstructed Load Deviations

Uninstructed load deviations are the difference between scheduled load and metered load.  If load deviations are positive (schedule exceeds meter), it is considered that excess supply was dispatched from the joint Utility/DWR portfolio in excess of quantity needed to serve retail load, and that the ISO credit for the excess supply should be shared pro rata as described above.  If load deviations are negative (meter exceed schedule), it is considered that Utility had to procure additional supply from ISO real time market.  The negative load deviation quantity procured from ISO real time market is considered a Utility market purchase and the quantity will be included in Utility Supply for pro rata share calculation purposes.

           Uninstructed Supply Deviations

Uninstructed supply deviations are the difference between scheduled supply and metered supply plus an ISO allocation for transmission losses.  Since all DWR Contract energy will be delivered to Utility as SC to SC transfers, no uninstructed energy deviations will be assessed by the ISO to DWR Contracts.  All uninstructed supply deviations, whether positive or negative, reflect over or under deliveries from Utility supply portfolio and purchases by Utility to cover allocated transmission losses.  Any supply deviation is considered as either a net Utility market purchase or a net Utility supply reduction, and the supply deviation quantity, positive or negative, will be included in Utility Supply for pro rata share calculation purposes.

           Transmission Losses

Transmission loss is defined as Energy that is lost due to the process of transmitting energy from supply source to load.  Therefore, supply resources from DWR Contracts and Utility Supply have distinct and identifiable quantity of transmission losses.  Utility and DWR Supply should be net of transmission losses because of energy that is delivered to retail customers (i.e. load) equals quantity of supply les losses.

          B.      Utility Remittance to DWR for Sales of DWR Energy to Utility Retail Customers –Energy Payment

Utility shall remit to DWR its Energy Payments according to the terms of each Utility's respective Servicing Arrangement.

The DWR Energy Payment is billed by each utility to customers in accordance with the terms of each applicable Utility Servicing Arrangement.  The DWR Energy Payment is billed kWhs served by Net DWR Supply at the applicable CPUC approved DWR rate.  Net DWR Supply is total DWR Supply less DWR share of surplus energy.  The DWR Energy Payment is allocated based on the percentage of energy supplied by DWR to Utility, which is the "Hourly Percentage Factor" multiplied by the retail load of each customer.  The Hourly Percentage Factor is determined by calculating the percentage of net energy supplied by DWR to Utility to serve retail load, as expressed below:

Hourly Percentage Factor = Net DWR Supply / (Net Utility Supply + Net DWR Supply)

Where:

Net DWR Supply is DWR Supply quantity used for the determination of DWR Surplus Energy Percentage less DWR share of surplus energy quantity, which is determined by the product of surplus energy multiplied by DWR Surplus Energy Percentage.

Net Utility Supply is Utility Supply quantity used for the determination of DWR Surplus Energy Percentage less Utility share of surplus energy quantity, which is total surplus energy less the DWR share of surplus energy quantity.

In the Event of any conflict between the formulas and procedures in this Exhibit C and the formulas and procedures in Utility's Servicing Arrangement, those contained in Utility's Servicing Arrangement shall govern.

          II.            Bilateral Settlement

Under the Contract Allocation Order DWR remains financially obligated for the Contracts. DWR will continue to pay suppliers and this requires DWR to apply appropriate procedures and controls to ensure that payments are made accurately and in a timely manner. Information supporting Contract settlements will be provided by Utility, and additional information may also be required to address contract performance issues (such as availability and other items as discussed in Exhibit E) and to allow DWR to settle disputes in an appropriate manner.

DWR requires sufficient information to support payment requests so that it can meet the accountability requirements of the State Controller's Office and the State Auditor, and simultaneously comply with the applicable statutes concerning disbursement of public monies. The Utility shall reconcile schedules with suppliers invoice.  DWR shall make the associated payments to suppliers after performing its verification, and Utility will provide the data as required in Exhibit F to allow it to perform these duties in a timely manner as set forth herein.

DWR shall continue to perform validation of settlement data and invoices and pay Contract costs directly to the suppliers upon validation of invoices.

          III.       Fuel Cost Verification and Settlement

Exhibit B provides a detailed discussion concerning Utility's responsibility for fuel management. DWR will continue to pay fuel suppliers and others involved in providing fuel management services for the delivery of fuel for those DWR Contracts where the Fuel Option has been elected.   Consistent with the above, Utility will perform settlements activities to reconcile quantities and associated charges, and DWR will perform verification, audit and monitoring to support its disbursement of funds.  Utility will comply with the requirements contained in Exhibit F to provide DWR with the necessary information to apply appropriate procedures and controls to ensure that fuel payments and payments for fuel management services are made accurately and in a timely manner and to allow DWR to settle disputes in an appropriate manner.

PG&E EXHIBIT D

ISO SCHEDULING COORDINATOR CHARGES

EXHIBIT D

ISO SCHEDULING COORDINATOR CHARGES

          The financial obligation for ISO charges incurred as of the  Effective Date will be allocated to the Utility, unless otherwise extended under the existing and any future  Applicable Commission Orders.  Unless specifically provided in Exhibit C hereto, all ISO charges incurred after the Effective Date attributable to load and resources shall be the responsibility of Utility.  

          Utility agrees that any refunds, reruns or credits through the ISO attributable to costs incurred by DWR for trade dates beginning Hour Ending 2200, January 17, 2001  up to the Effective Date, which are separate from ISO charges subject to Commission Decision No. 02-05-048, shall belong to DWR and Utility shall take all necessary action to remit such refunds or credits to DWR within reasonable time.  In addition, DWR shall be responsible for any ISO charges incurred during this period pursuant to the existing letter agreement between the Parties.  Utility shall invoice DWR for such ISO charges within a reasonable period of time and DWR shall pay Utility for such ISO charges within 10 days of receipt of such invoice.  Without making any assurances as to Commission action, DWR agrees to take appropriate action to ensure that such refunds or credits are applied consistent with DWR's Revenue Requirement cost allocation method for the same trade dates.

          DWR agrees that any refunds, reruns, or credits through the ISO attributable to ISO charges invoiced to DWR under the November 7, 2001 order of the Federal Energy Regulatory Commission and subsequent orders but which are further subject to Commission Decision No.02-05-048, which directs Utility to directly reimburse DWR for such ISO charges incurred starting Hour Ending 2200, January 17, 2001 up to the Effective Date, shall belong to Utility and DWR shall take all necessary action to remit such refunds or credits directly to Utility within reasonable time.

PG&E EXHIBIT E

CONTRACT MANAGEMENT AND
ADMINISTRATION PROTOCOLS

EXHIBIT E

CONTRACT MANAGEMENT AND ADMINISTRATION PROTOCOLS

DWR will retain all contract management, administration and monitoring responsibilities for the Contracts, including due diligence, performance testing, contract performance assessment, formal correspondence and notifications with Suppliers, exercise of contract options, contract interpretation and dispute resolution, and financial reporting.  In the event Utility and DWR agree in the future to transition the Due Diligence and Performance Test Monitoring functions set forth in this Exhibit E from DWR to the Utility, the Parties will first develop a mutually acceptable plan of performance, a transition schedule, and a transition plan for transfer of such functions from DWR to the Utility for review and approval by the Commission. . Upon agreement of the Parties to an acceptable plan and completion of the transition period, the agreed upon functions will transfer from DWR to the Utility ("the Transition Date").

I.  Due-Diligence

The Due Diligence function assesses the progress of permitting, construction and performance capability of new generating facilities under to the Contracts.  Due Diligence includes (i) monitoring activities associated with the development, construction, and performance of new generating facilities; (ii) identification and tracking of key projects milestones including permitting, equipment procurement, construction, commissioning, and performance testing; (iii) coordination with permitting agencies and the Suppliers, review of project documents, physical inspections, and witnessing of acceptance tests, (iv) verification that the new facilities can perform in a manner that is consistent with the obligations under the appropriate Contract and (v) review and approval of commercial operation dates and documentation.

II.  Performance Test Monitoring

A.   Annual Performance Tests

Annual Performance Tests verify ongoing compliance with the Contracts and establish plants capacities and efficiencies that are used to calculate contract payments, either for capacity or energy.  Annual Performance Test responsibilities generally consist of (i) verification of testing procedures, (ii) witness of performance tests, (iii) review of test results and test reports for compliance with Contract terms and conditions, and (iv) identification of contract non-compliance for dispute resolution with the Supplier.  Prior to the Transition Date, the Utility will cooperate and assist DWR with scheduling of upcoming Annual Performance Tests, and the Utility may have its staff witness such testing. 

B.   Scheduled Performance Tests

Prior to the Transition Date, on occasion, DWR may request that Utility schedule a peaking or dispatchable generating facility for testing (to assure that such generation facility is available according to the terms of the contract between such generation facility and DWR). The utility will cooperate and shall coordinate with the DWR on a mutually acceptable date for performance of the test.  On the date agreed upon, the Utility shall schedule the specified facility or unit for operation to test the availability, reliability, and performance of the scheduled unit. 

C.   Test Procedures and Protocols

Prior to January 1, 2003, Utility shall meet with DWR staff to review, discuss, and verify test procedures and protocols developed by DWR. 

III.  Contract Performance Assessments

DWR shall continue to perform an after-the-fact review ("Performance Assessment") of each Contract on a periodic basis.  The purpose of the Performance Assessment is to assess, analyze, and document the overall performance of each contract Supplier, assure that the Supplier is satisfying the terms and conditions of their respective contract(s), and identify potential issues, disputes, and other matters that may require corrective action by either Utility or DWR as part of contract administration. 

IV.  Other Administrative Matters

A.   Correspondence with Suppliers

Utility and DWR agree to copy each other on all written correspondence and written notifications sent to or received from a Supplier of an Allocated Contract or Interim Contract related to the activities described in this Exhibit E. The Parties agree to provide additional information as requested related to verification and support of the activities described in this Exhibit E.

B.   Reports

Results of the activities described in this Exhibit E will be documented by DWR in written reports ("Reports") and shall be discussed periodically between DWR and the Utility.  Such Reports may include, but are not limited to, summary of test results, status of projects, recommendations for operational changes, procedural changes, dispute resolution, and results of Performance Assessments. 

Such Reports, documentation, or other material developed by either Party shall be shared and reviewed with the other Party on a timely basis.

PG&E EXHIBIT F

DWR DATA REQUIREMENTS FROM UTILITY

EXHIBIT F

DWR DATA REQUIREMENTS FROM UTILITY

To effectively fulfill its legal and financial responsibilities, DWR requires access to standard and reliable information on a timely basis. Post transition, DWR remains statutorily and contractually obligated to collect, account for, and remit funds for the power it provides to the IOU's retail customers.  More specifically, post transition, DWR must have readily available access to information that is currently available in-house due to DWR's operational responsibilities.  The primary source of this information post transition will be the three utilities.

The information being requested is required to:

· Verify, audit, monitor and authorize payment for bilateral invoices for allocated DWR contracts;

· Manage disputes between DWR and the bilateral counterparties;

· Manage disputes between DWR and the bilateral counterparties;

· Verify, audit, monitor and authorize payment for fuel procured by the utilities relating to DWR allocated contracts;

· Verify, audit, monitor, collect and IOU remittances relating to repayment of Energy Supplied and Bond Funds;

· Forecast, manage and monitor DWR monetary requirements and associated accounts;

· Ongoing reporting responsibilities under AB1X, the rate agreement and bond indenture;

· Audit and monitor long-term contract performance and associated risks prior to contract assignment or novation.

The table below contains a brief description of the information to be provided by Utility, the frequency for which Utility shall provide such information to DWR, and the effective date for when Utility shall provide such information to DWR.

The following table outlines DWR data requirements relating to general contract/trade information:

Contract/Trade
Requirement	Description	Freq	Effective	Delivery Method
Surplus Energy Sales Plan	Monthly utility's surplus energy sales plan updated weekly.  Sales plan will outline all surplus sales contemplated by the utility, including but not limited to balance of month, weekly balance of week and other short-term sales.	Monthly plan, updated weekly	1/1/2003	Email/Fax - Standard Form TBD
Surplus Energy Sales	Contract/Deal information relating to the forward sale of DWR surplus energy.  This would include but is not limited to Counter party, Term (Start/End Date), Hourly Contract Volumes, Hourly Price, Location, any fee information, etc.	When executed	All surplus forward sales  entered into after 1/1/2003	Email/Fax - Standard Form TBD

The following table outlines DWR data requirements relating to long-term contract schedule information and associated bilateral invoices:

Schedule/Bilateral Invoice
Requirement	Description	Freq	Effective	Delivery Method
Final Schedule Volumes, Long Term Contracts	For all long-term contracts allocated to the utilities and any surplus energy sales, the detailed hourly final schedule volumes and pricing information by contract by counterparty, by day. Final schedule volumes are defined as the final volume for the hour at the completion of the real-time market.  These volumes represent the hour ahead scheduled volumes adjusted to include any real-time market adjustments by the ISO.  Absent any real time adjustments, this data will be the same as Final Hour Ahead Schedule. File should include, but is not limited to; Utility identifier, file type identifier (i.e. final, HA), SC identifier, counterparty identifier, contract identifier, schedule type identifier (i.e. sale), delivery location, date, volume scheduled by hour, price per hour.	T+1 (Daily)	1/2/2003	Secure Electronic – Format TBD
Hour Ahead  Schedule Volumes, Long Term Contracts	For all long-term contracts allocated to the utilities and any surplus energy sales, the detailed hour ahead final schedule volumes and pricing information by contract, by counterparty, by day. Format and data elements of the file provided should be identical to what was specified above in Final Schedule volumes. (Note: This cannot be the ISO Hour Ahead Final Schedule template as this file does not provide transactional level details but consolidates/collapses information based on certain ISO rules.)	T+1 (Daily)	1/2/2003	Secure Electronic – Format TBD
Reconciled Monthly bilateral invoices	Monthly invoice and supporting documentation for bilateral contracts relating to DWR long-term contracts, reviewed and approved by utility for payment by DWR to the counterparyy.	Monthly – 5 business days prior to payment due date	Feb 03	TBD

In the event of a bilateral invoice dispute with the counterparty, DWR may also request from the utility the additional schedule information.  This information would be in the same format as outlined in the table above.  As mentioned above, DWR is requesting transactional level information and not the associated ISO template files due to the consolidation/collapsing of schedules with the template files.  Schedule information required would include :

· Hour Ahead Preferred Schedule Volumes

· Day Ahead Final Schedule Volumes

· Day Ahead Adjusted Schedule Volumes

· Day Ahead Revised Preferred Schedule Volumes

· Day Ahead Preferred Schedule Volumes

The following table outlines DWR data requirements relating to the verification of fuel costs.  It assumes DWR will retain legal and financial responsibility for gas and related services while the utility will perform administrative and operational responsibilities as outlined in Exhibit B.

Fuel Costs
Requirement	Description	Freq	Effective	Delivery Method
Generator fuel plan proposal	Proposal and supporting analysis on whether or not to accept or reject of generator fuel plan.	Based on individual contracts	Jan-03	TBD
Utility Fuel Procurement Plan	Utility will provide a bi-annual fuel procurement plan for utility supplied fuel.	Bi-Annual	Jan-03	TBD
Tolling agreement Settlement Report	Monthly report on each DWR tolling agreement that includes but is not limited to: tolling contract identifier, who provided the gas (generator/utility) and daily quantity of gas supplied.	Monthly	Feb-03	Electronic Format TBD
Reconciled Monthly Gas Invoice	Suppliers monthly invoice and supporting documentation for fuel procurement relating to DWR tolling agreements, reviewed and approved by Utility for payment by DWR to the supplier.	Monthly – 5‑business days prior to payment due date	Feb-03	Electronic – Format TBD
Gas Transportation Contract Information	Details relating to the Utility negotiated firm and/or interruptible transportation agreements for DWR review and authorization.	When executed	All contracts effective after 1/1/2003	E-mail/Fax Standard Form TBD
Gas Storage Contract Information	Details relating to the Utility/negotiated firm and/or interruptible storage agreements for DWR review and authorization.	When executed	All contracts effective after 1/1/03	E-mail/Fax Standard Form TBD
Reconciled Monthly gas transportation invoices	Suppliers monthly invoice and supporting documentation for natural gas transportation costs relating to DWR tolling agreements, reviewed and approved by utility for payment by DWR to the supplier.	Monthly – 5‑business days prior to payment due date	Feb-03	Electronic – Format TBD
Reconciled  Monthly gas storage invoices	Supplier's monthly invoice and supporting documentation for storage relating to DWR tolling agreements, reviewed and approved by utility for payment by DWR to the supplier.	Monthly – 5‑business days prior to payment due date	Feb-03	Electronic – Format TBD

The following table outlines additional DWR data relating to utility revenue remittance:

Utility Revenue Remittance
Requirement	Description	Freq	Effective	Delivery Method
Utility ISO Preliminary Settlement and Supporting Files	The complete Utility preliminary settlement statement and supporting files in original ISO template format.	T + 38 business days	Ongoing	Secure Electronic-ISO Template Direct from ISO
Utility Final ISO Settlement Statement and Supporting Files	The complete Utility final ISO settlement statement and supporting files in ISO original template format.  This information also required for remittance calculation purposes.	T + 45 business days	Ongoing	Secure Electronic-ISO Template Direct from ISO
Scheduled Retail Load by hour	Utilities estimated retail load information by hour, by day used for the preliminary remittance.	T + 1	1/1/2003	TBD
Hourly aggregate final schedule of Utility's resource portfolio	Utilities total hourly scheduled volumes for the entire Utilities portfolio.  This is an aggregate total for the day, by hour and represents the total volume supplied by the utility.	T+1 (Daily)	1/2/2003	TBD
Wholesale Obligation Volumes	Utilities total hourly scheduled volumes for pre-existing wholesale commitments in aggregate by the hour for each day.	T+1 (Daily)	1/2/03	TBD
Hourly Distribution Loss Factor	Utility DLF % by hour	When changes required	1/1/2003	TBD
Estimated DWR remittance %	Utility estimated remittance percentage.	When changes required	1/1/2003	TBD
Energy Sales billed (kWh)*	Monthly kWh billed by Utility to end users	Monthly	Ongoing	Standard DWR Form/File (TBD)
DWR Power Charge volumes*	Monthly kWh billed by Utility to end users	Monthly	Ongoing	Standard DWR Form/File (TBD)
DWR Power Charge billed to Customer*	Monthly dollar amount of DWR Power Charge being billed to customer including identification of dates billed.	Monthly	Ongoing	Standard DWR Form/File (TBD)	Ongoing	Standard DWR Form/File
DWR Power Charge Remitted to DWR*	Daily dollar amount being remitted by Utility to DWR for the DWR Power Charge collected from customers including identification of dates billed.	Daily	Ongoing	Standard DWR Form/File (TBD)

*This information is already provided pursuant to the Servicing Arrangement, and supports the daily remittance calculation for each month and subsequent true-ups.  The Servicing Arrangement will be modified as necessary to conform to this Operating Agreement.

As various Commission proceedings are finalized DWR will also require specific data related to Bond Charge remittances and to Direct Access exit fees.  The specific nature and format of this data will be agreed with between the utilities and DWR.

The following table outlines DWR data requirements relating to resource information:

Resource Information
Requirement	Description	Freq	Effective	Delivery Method
Load and Resource Assessment Studies	Copies of Utilities annual and quarter load and resource assessment studies as provided to the PUC.	Annually and quarterly	Jan-03	TBD
Update Description of Resources	Updated description of URG resources .	Annually or when significant changes	Jan 1, 04	TBD
Unit Commitment Studies	As provided to the PUC.	Weekly	Jan-03	TBD
DWR Non-Dispatched Resources Report	Report of Resources that were economic to run, but were not dispatched.	Ad hoc	1/1/03	TBD
DWR Resource Unavailability Form	Utility notification to DWR for resources within an allocated contracts becoming unavailable, or scheduled to become unavailable. Note: This information could be provided directly from the generator to DWR and would therefore not be required from Utility.	As outlined in operating agreement	1/1/2003	Standard DWR Form – Email/Fax

Upon the reasonable request of DWR, Utility will provide to DWR any information in respect of Utility that is applicable to the rights and obligations of the Parties under this Agreement or any material information that is reasonably necessary for DWR to monitor and manage their risks and perform their fiduciary responsibilities.  Upon the reasonable request of Utility, DWR will provide to Utility any information in respect of DWR that is applicable to the rights and obligations of the Parties under this Agreement or any material information that is reasonably necessary for Utility to operationally administer Contracts under this Agreement.

For the information identified above, or any additional information identified through the term of this Agreement, standard submission formats will be used or be developed by DWR for use by each of the investor-owned utilities, including Utility.  In the cases where the information requirements result in a large volume of data (e.g., schedule information), DWR will use or develop standard detailed file definitions for use by all of the investor-owned utilities, including Utility.  Data will be submitted to DWR by Utility through a secure electronic communication medium, unless other medium is reasonably requested by DWR.

As a result of the relative short implementation timeframes, it is anticipated an interim delivery protocol (e.g., comma delimited file via email, compact diskettes) will be utilized until the final data transmission media are in place.  DWR shall work jointly with Utility to ensure the required data is available by January 1, 2003.

In the event that DWR incurs additional costs, including but not limited to penalties, interest or other such costs, due to Utility's failure to timely provide the data set forth in this Exhibit F, any such direct cost increase invoiced or assessed to DWR shall be borne by Utility.

The provisions of this Exhibit are subject to annual review by DWR and Utility to ensure that data reporting remains relevant and useful.

EX-10.2.1

Exhibit 10.2.1

AGREEMENT AND RELEASE

April 18, 2003

To: Robert D. Glynn, Jr.

Dear Bob:

This letter agreement (the "Agreement") by and between PG&E Corporation (the "Company") as grantor of the trust pursuant to the Supplemental Executive Retirement Plan of Pacific Gas and Electric Company (the "SERP"), and you ("Executive"), addresses Executive's benefits under the SERP.

RECITALS

(1)	Executive is a participant in the SERP.
(2)	The Company has agreed to purchase annuity contracts on Executive's behalf with AIG Life Insurance Company and John Hancock Life Insurance Company in complete satisfaction of Executive's benefits accrued under the SERP through December 31, 2002.

AGREEMENTS AND ACKNOWLEDGMENTS

(1)	In consideration of the establishment and funding of contract number GA-1147 with AIG Life Insurance Company and contract number 15340 with John Hancock Life Insurance Company (the "Annuity Contracts") and the delivery to Executive of certificates under the Annuity Contracts, Executive acknowledges and agrees that all of Executive's benefits accrued under the SERP as of December 31, 2002 ("Accrued Benefits") have been fully satisfied and discharged.
(2)	Executive further acknowledges and agrees that the Company, Pacific Gas and Electric Company and their subsidiaries and affiliates shall have no further liability or obligation with respect to payment of the Accrued Benefits.
(3)	Executive further agrees that any claim or dispute related to the Accrued Benefits shall relate not to the SERP but rather solely to the Annuity Contracts, and Executive releases from all liability and agrees not to bring any claim, complaint or dispute against the SERP, the trust pursuant to the SERP, the Company, Pacific Gas and Electric Company or any of their subsidiaries, affiliates, officers, employees or consultants with respect to the Accrued Benefits.
(4)	The Company and Executive agree that all of their respective rights under Section 1542 of the Civil Code of the State of California, arising at any time prior to the date this Agreement is mutually executed by the parties, which are related or in any manner incidental to the matters encompassed by this Agreement are hereby waived. Section 1542 provides as follows:

"A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR."

This Agreement constitutes the entire agreement between Executive and the Company with respect to the subject matter of this Agreement and may only be modified or amended by a writing signed by Executive and the Company.

By signing below, you agree to all the terms of this Agreement.

PG&E CORPORATION

By

        /s/ G. Brent Stanley

            G. Brent Stanley

         Senior Vice President

        /s/ Robert D. Glynn, Jr.

            Robert D. Glynn, Jr.

EX-10.2.2

Exhibit 10.2.2

AGREEMENT AND RELEASE

April 18, 2003

To: Gordon R. Smith

Dear Gordon:

This letter agreement (the "Agreement") by and between PG&E Corporation (the "Company"), as grantor of the trust pursuant to the Supplemental Executive Retirement Plan of Pacific Gas and Electric Company (the "SERP"), and you ("Executive"), addresses Executive's benefits under the SERP.

RECITALS

(1)	Executive is a participant in the SERP.
(2)	The Company has agreed to purchase annuity contracts on Executive's behalf with AIG Life Insurance Company and John Hancock Life Insurance Company in complete satisfaction of Executive's benefits accrued under the SERP through December 31, 2002.

AGREEMENTS AND ACKNOWLEDGMENTS

(1)	In consideration of the establishment and funding of contract number GA-1147 with AIG Life Insurance Company and contract number 15340 with John Hancock Life Insurance Company (the "Annuity Contracts") and the delivery to Executive of certificates under the Annuity Contracts, Executive acknowledges and agrees that all of Executive's benefits accrued under the SERP as of December 31, 2002 ("Accrued Benefits") have been fully satisfied and discharged.
(2)	Executive further acknowledges and agrees that the Company, Pacific Gas and Electric Company and their subsidiaries and affiliates shall have no further liability or obligation with respect to payment of the Accrued Benefits.
(3)	Executive further agrees that any claim or dispute related to the Accrued Benefits shall relate not to the SERP but rather solely to the Annuity Contracts, and Executive releases from all liability and agrees not to bring any claim, complaint or dispute against the SERP, the trust pursuant to the SERP, the Company, Pacific Gas and Electric Company or any of their subsidiaries, affiliates, officers, employees or consultants with respect to the Accrued Benefits.
(4)	The Company and Executive agree that all of their respective rights under Section 1542 of the Civil Code of the State of California, arising at any time prior to the date this Agreement is mutually executed by the parties, which are related or in any manner incidental to the matters encompassed by this Agreement are hereby waived. Section 1542 provides as follows:

"A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR."

This Agreement constitutes the entire agreement between Executive and the Company with respect to the subject matter of this Agreement and may only be modified or amended by a writing signed by Executive and the Company.

By signing below, you agree to all the terms of this Agreement.

PG&E CORPORATION

By

         /s/ G. Brent Stanley

             G. Brent Stanley

            Senior Vice President

          /s/ Gordon R. Smith

              Gordon R. Smith

EX-10.2.3

Exhibit 10.2.3

AGREEMENT AND RELEASE

April 18, 2003

To: James K. Randolph

Dear Jim:

This letter agreement (the "Agreement") by and between PG&E Corporation (the "Company"), as grantor of the trust pursuant to the Supplemental Executive Retirement Plan of Pacific Gas and Electric Company (the "SERP"), and you ("Executive"), addresses Executive's benefits under the SERP.

RECITALS

(1)	Executive is a participant in the SERP.
(2)	The Company has agreed to purchase annuity contracts on Executive's behalf with AIG Life Insurance Company and John Hancock Life Insurance Company in complete satisfaction of Executive's benefits accrued under the SERP through December 31, 2002.

AGREEMENTS AND ACKNOWLEDGMENTS

(1)	In consideration of the establishment and funding of contract number GA-1147 with AIG Life Insurance Company and contract number 15340 with John Hancock Life Insurance Company (the "Annuity Contracts") and the delivery to Executive of certificates under the Annuity Contracts, Executive acknowledges and agrees that all of Executive's benefits accrued under the SERP as of December 31, 2002 ("Accrued Benefits") have been fully satisfied and discharged.
(2)	Executive further acknowledges and agrees that the Company, Pacific Gas and Electric Company and their subsidiaries and affiliates shall have no further liability or obligation with respect to payment of the Accrued Benefits.
(3)	Executive further agrees that any claim or dispute related to the Accrued Benefits shall relate not to the SERP but rather solely to the Annuity Contracts, and Executive releases from all liability and agrees not to bring any claim, complaint or dispute against the SERP, the trust pursuant to the SERP, the Company, Pacific Gas and Electric Company or any of their subsidiaries, affiliates, officers, employees or consultants with respect to the Accrued Benefits.
(4)	The Company and Executive agree that all of their respective rights under Section 1542 of the Civil Code of the State of California, arising at any time prior to the date this Agreement is mutually executed by the parties, which are related or in any manner incidental to the matters encompassed by this Agreement are hereby waived. Section 1542 provides as follows:

"A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR."

This Agreement constitutes the entire agreement between Executive and the Company with respect to the subject matter of this Agreement and may only be modified or amended by a writing signed by Executive and the Company.

By signing below, you agree to all the terms of this Agreement.

PG&E CORPORATION

By

         /s/ G. Brent Stanley             

             G. Brent Stanley

            Senior Vice President

           /s/ James K. Randolph                  

              James K. Randolph

EX-10.2.4

Exhibit 10.2.4

AGREEMENT AND RELEASE

April 18, 2003

To: Gregory M. Rueger

Dear Greg:

This letter agreement (the "Agreement") by and between PG&E Corporation (the "Company"), as grantor of the trust pursuant to the Supplemental Executive Retirement Plan of Pacific Gas and Electric Company (the "SERP"), and you ("Executive"), addresses Executive's benefits under the SERP.

RECITALS

(1)	Executive is a participant in the SERP.
(2)	The Company has agreed to purchase annuity contracts on Executive's behalf with AIG Life Insurance Company and John Hancock Life Insurance Company in complete satisfaction of Executive's benefits accrued under the SERP through December 31, 2002.

AGREEMENTS AND ACKNOWLEDGMENTS

(1)	In consideration of the establishment and funding of contract number GA-1147 with AIG Life Insurance Company and contract number 15340 with John Hancock Life Insurance Company (the "Annuity Contracts") and the delivery to Executive of certificates under the Annuity Contracts, Executive acknowledges and agrees that all of Executive's benefits accrued under the SERP as of December 31, 2002 ("Accrued Benefits") have been fully satisfied and discharged.
(2)	Executive further acknowledges and agrees that the Company, Pacific Gas and Electric Company and their subsidiaries and affiliates shall have no further liability or obligation with respect to payment of the Accrued Benefits.
(3)	Executive further agrees that any claim or dispute related to the Accrued Benefits shall relate not to the SERP but rather solely to the Annuity Contracts, and Executive releases from all liability and agrees not to bring any claim, complaint or dispute against the SERP, the trust pursuant to the SERP, the Company, Pacific Gas and Electric Company or any of their subsidiaries, affiliates, officers, employees or consultants with respect to the Accrued Benefits.
(4)	The Company and Executive agree that all of their respective rights under Section 1542 of the Civil Code of the State of California, arising at any time prior to the date this Agreement is mutually executed by the parties, which are related or in any manner incidental to the matters encompassed by this Agreement are hereby waived. Section 1542 provides as follows:

"A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR."

This Agreement constitutes the entire agreement between Executive and the Company with respect to the subject matter of this Agreement and may only be modified or amended by a writing signed by Executive and the Company.

By signing below, you agree to all the terms of this Agreement.

PG&E CORPORATION

By

           /s/ G. Brent Stanley                    

             G. Brent Stanley

           Senior Vice President

           /s/ Gregory M. Rueger             

              Gregory M. Rueger

EX-10.2.5

Exhibit 10.2.5

AGREEMENT AND RELEASE

April 18, 2003

To: Bruce R. Worthington

Dear Bruce:

This letter agreement (the "Agreement") by and between PG&E Corporation (the "Company"), as grantor of the trust pursuant to the Supplemental Executive Retirement Plan of Pacific Gas and Electric Company (the "SERP"), and you ("Executive"), addresses Executive's benefits under the SERP.

RECITALS

(1)	Executive is a participant in the SERP.
(2)	The Company has agreed to purchase annuity contracts on Executive's behalf with AIG Life Insurance Company and John Hancock Life Insurance Company in complete satisfaction of Executive's benefits accrued under the SERP through December 31, 2002.

AGREEMENTS AND ACKNOWLEDGMENTS

(1)	In consideration of the establishment and funding of contract number GA-1147 with AIG Life Insurance Company and contract number 15340 with John Hancock Life Insurance Company (the "Annuity Contracts") and the delivery to Executive of certificates under the Annuity Contracts, Executive acknowledges and agrees that all of Executive's benefits accrued under the SERP as of December 31, 2002 ("Accrued Benefits") have been fully satisfied and discharged.
(2)	Executive further acknowledges and agrees that the Company, Pacific Gas and Electric Company and their subsidiaries and affiliates shall have no further liability or obligation with respect to payment of the Accrued Benefits.
(3)	Executive further agrees that any claim or dispute related to the Accrued Benefits shall relate not to the SERP but rather solely to the Annuity Contracts, and Executive releases from all liability and agrees not to bring any claim, complaint or dispute against the SERP, the trust pursuant to the SERP, the Company, Pacific Gas and Electric Company or any of their subsidiaries, affiliates, officers, employees or consultants with respect to the Accrued Benefits.
(4)	The Company and Executive agree that all of their respective rights under Section 1542 of the Civil Code of the State of California, arising at any time prior to the date this Agreement is mutually executed by the parties, which are related or in any manner incidental to the matters encompassed by this Agreement are hereby waived. Section 1542 provides as follows:

"A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR."

This Agreement constitutes the entire agreement between Executive and the Company with respect to the subject matter of this Agreement and may only be modified or amended by a writing signed by Executive and the Company.

By signing below, you agree to all the terms of this Agreement.

PG&E CORPORATION

By

         /s/ G. Brent Stanley               

             G. Brent Stanley

           Senior Vice President

           /s/ Bruce R.Worthington             

               Bruce R. Worthington

EX-10.3

Exhibit 10.3

June 18, 2003

Mr. Thomas B. King
5059 Sedgwick Street, N.W.
Washington, D.C. 20016

Dear Tom,

Having received the approval of the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors, I am pleased to offer you the following modifications to your current compensation package:

• Relocation Assistance: Effective July 1, 2003, your relocation assistance subsidy will be increased to $3,750 per month. Assuming your continued employment with PG&E Corporation, that benefit will be provided to you through June 2007, under the provisions of the company's relocation benefits.

• Retention Program: PG&E Corporation will assume the obligation currently held by NEG under the terms of the NEG Management Retention Program to provide you with a retention payment of $150,000 in October 2003, provided that you remain employed by PG&E Corporation until such time.

• Defined Benefit Pension Arrangement: Effective July 1, 2003, you will become a participant in our defined benefit supplemental executive retirement plan. Initially, you will be provided with five years of credited service under the plan. While you will earn additional credited service for each year you are employed, you will also be provided with an additional five years of credited service under the plan on or about July 1, 2008, provided you remain employed by the organization until such time.

Tom, you are and continue to be a very valued member of my senior management team. I am confident in your abilities and see you as a key player in the future of PG&E Corporation.

Sincerely,

/s/ Robert D. Glynn, Jr.

Robert D. Glynn, Jr.

Accepted: /s/ Thomas B. King

Date: June 19, 2003

EX-10.4

Exhibit 10.4

August 15, 2003

Peter Darbee

Dear Peter:

Having received the approval of the Nominating, Compensation and Governance Committee of the PG&E Corporation Board of Directors, I am pleased to offer you the following modifications to your current compensation package:

• Defined Benefit Pension Arrangement: Effective July 1, 2003, you will
  become a participant in our defined benefit supplemental executive retirement
  plan. Initially, you will be provided with five years of credited service under
  the plan. While you will earn additional credited service for each year you are
  employed, you will also be provided with an additional five years of credited
  service under the plan on or about July 1, 2008, provided you remain
  employed by the organization until such time.

Peter, you are and continue to be a very valued member of my senior management
team. I am confident in your abilities and see you as a key player in the future
of PG&E Corporation.

Sincerely,

/s/ Robert D. Glynn, Jr.

Robert D. Glynn, Jr.

EX-11

EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS (LOSS) PER COMMON SHARE

			Three months ended				Six months ended
			June 30,				June 30,
(in millions, except per share amounts)			2003		2002 (1)		2003		2002 (1)
Income (Loss) from continuing operations			$	219	$	279	$	(59)	$	903
Discontinued operations				8		-		(62)		7
Net income (loss) before cumulative effect of changes
	in accounting principles		227		279		(121)		910
Cumulative effect of changes in accounting principles			-		(61)		(6)		(61)
Net Income (Loss)			227		218		(127)		849
Interest expense on 9.5% Convertible Subordinated Notes (2)			4		-		-		-
Net Income (Loss) for Diluted Calculations			$	231	$	218	$	(127)	$	849
Weighted average common shares outstanding, basic (3)			384		366		383		365
Add:		Employee stock options and PG&E Corporation
		shares held by grantor trusts	2		5		-		5
		PG&E Corporation Warrants (4)	5		-		-		-
		9.5% Convertible Subordinated Notes	18		1		-		-
Shares outstanding for diluted calculations			409		372		383		370
Earnings (Loss) Per Common Share, Basic
Income (loss) from continuing operations			$	0.57	$	0.76	$	(0.15)	$	2.48
Discontinued operations			0.02		-		(0.16)		0.02
Cumulative effect of changes in accounting principles			-		(0.16)		(0.02)		(0.17)
Net earnings (loss)			$	0.59	$	0.60	$	(0.33)	$	2.33
Earnings (Loss) Per Common Share, Diluted (5)
Income (loss) from continuing operations			$	0.54	$	0.75	$	(0.15)	$	2.44
Discontinued operations			0.02		-		(0.16)		0.02
Cumulative effect of changes in accounting principles			-		(0.16)		(0.02)		(0.17)
Net earnings (loss)			$	0.56	$	0.59	$	(0.33)	$	2.29

(1) Prior year amounts have been restated to reflect the reclassification of USGenNE, Mountain View, ET Canada and Ohio Peakers operating results to discontinued operations.

(2) Interest expense, including amortization of the discount, on the 9.50 percent Convertible Subordinated Notes for the three and six months ended June 30, 2002, was $232,276, net of income tax of $159,724.

(3) Weighted average common shares outstanding exclude shares held by a subsidiary of PG&E Corporation (23,815,500 shares at June 30, 2003 and 2002) and PG&E Corporation shares held by grantor trusts to secure deferred compensation obligations (281,985 shares at June 30, 2003 and 2002).

(4) The incremental shares associated with PG&E Corporation Warrants were 157,995 shares for the three months ended June 30, 2002, and 79,433 shares for the six months ended June 30, 2002.

(5) The diluted earnings per share for the six months ended June 30, 2003, excludes approximately 1 million incremental shares related to employee stock options and shares held by grantor trusts, 5 million incremental shares related to warrants, and 18 million incremental shares related to the 9.5 percent Convertible Subordinated Notes, and includes associated interest expense of $8 million (net of income taxes of $6 million) due to the anti-dilutive effect upon loss from continuing operations.

EX-12.1

EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY
A DEBTOR-IN-POSSESSION
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Three months ended June 30,		Six months ended June 30,		Year ended December 31,
(in millions)	2003		2003		2002		2001		2000			1999		1998
Earnings:
Net income (loss)	$	345	$	272	$	1,819	$	1,015	$	(3,483)		$	788	$	729
Adjustments for minority interest   in losses of less than 100% owned   affiliates and the Company's equity   in undistributed income (losses)   of less than 50% owned affiliates	- -		-		- -		- -		- -			- -		- -
Income taxes provision (benefit)	209		125		1,178		596		(2,154)			648		629
Net fixed charges	230		458		1,029		1,019		648			637		673
Total Earnings (Loss)	$	784	$	855	$	4,026	$	2,630	$	(4,989)		$	2,073	$	2,031
Fixed Charges:
Interest on short-term borrowings   and long-term debt, net	$	226	$	448	$	996	$	981	$	616		$	604	$	635
Interest on capital leases	-		1		2		2		2			3		2
AFUDC debt	4		9		21		12		6			7		12
Earnings required to cover the   preferred stock dividend and   preferred security distribution   requirements of majority owned   trust	- -		-		10		24		24			24		24
Total Fixed Charges	$	230	$	458	$	1,029	$	1,019	$	648		$	638	$	673
Ratios of Earnings (Loss) to   Fixed Charges	3.41		1.87		3.91		2.58		(7.70)		(1)		3.25	3.02

Note:

For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to fixed charges, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest of subordinated debentures held by trust, interest on capital leases, and earnings required to cover the preferred stock dividend requirements.

⁽¹⁾ The ratio of earnings to fixed charges indicates a deficiency of less than one-to-one coverage aggregating $5,637 million.

EX-12.2

EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY
A DEBTOR-IN-POSSESSION
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED
FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

	Three months ended June 30,		Six months ended June 30,		Year ended December 31,
(in millions)	2003		2003		2002		2001		2000			1999		1998
Earnings:
Net income (loss)	$	345	$	272	$	1,819	$	1,015	$	(3,483)		$	788	$	729
Adjustments for minority interest in   losses of less than 100% owned   affiliates and the Company's equity   in undistributed income (losses) of   less than 50% owned affiliates	-		-		-		-		-			-		-
Income taxes provision (benefit)	209		125		1,178		596		(2,154)			648		629
Net fixed charges	230		458		1,029		1,019		648			637		673
Total Earnings (Loss)	$	784	$	855	$	4,026	$	2,630	$	(4,989)		$	2,073	$	2,031
Fixed Charges:
Interest on short-term borrowings   and long-term debt, net	$	226	$	448	$	996	$	981	$	616		$	604	$	635
Interest on capital leases	-		1		2		2		2			3		2
AFUDC debt	4		9		21		12		6			7		12
Earnings required to cover the   preferred stock dividend and   preferred security distribution   requirements of majority owned trust	-		-		10		24		24			24		24
Total Fixed Charges	230		458		1,029		1,019		648			638		673
Preferred Stock Dividends:
Tax deductible dividends	2		4		9		9		9			9		9
Pretax earnings required to cover   non-tax deductible preferred stock   dividend requirements	7		14		28		27		27			27		31
Total Preferred Stock Dividends	9		18		37		36		36			36		40
Total Combined Fixed Charges and   Preferred Stock Dividends	$	239	$	476	$	1,066	$	1,055	$	684		$	674	$	713
Ratios of Earnings (Loss) to   Combined Fixed Charges and   Preferred Stock Dividend	3.28		1.80		3.78		2.49		(7.29)		(1)		3.08	2.85

Note:

For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to combined fixed charges and preferred stock dividends, "earnings" represent net income adjusted for the minority interest in losses of less than 100% owned affiliates, cash distributions from and equity in undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges" include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, interest of subordinated debentures held by trust, and earnings required to cover the preferred stock dividend requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax earnings that are required to pay the dividends on outstanding preference securities.

(1) The ratio of earnings to combined fixed charges and preferred stock dividends indicates a deficiency of less than one-to-one coverage aggregating $5,673 million.

EX-18

Exhibit 18

August 19, 2003

PG&E Corporation
One Market Street, 24^th Floor
San Francisco, CA 94110


Dear Sirs/Madams:

At your request, we have read the description included in your Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended June 30, 2003, of the facts relating to the change from gross to net reporting of revenues and cost of sales at PG&E NEG, a consolidated subsidiary. We believe, on the basis of the facts so set forth and other information furnished to us by appropriate officials of the Company, that the accounting change described in your Form 10-Q is to an alternative accounting principle that is preferable under the circumstances.

We have not audited any consolidated financial statements of PG&E Corporation and its consolidated subsidiaries as of any date or for any period subsequent to December 31, 2002. Therefore, we are unable to express, and we do not express, an opinion on the facts set forth in the above-mentioned Form 10-Q, on the related information furnished to us by officials of the Company, or on the financial position, results of operations, or cash flows of PG&E Corporation and its consolidated subsidiaries as of any date or for any period subsequent to December 31, 2002.

Yours truly,

DELOITTE & TOUCHE LLP

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Robert D. Glynn, Jr., certify that:

1.  I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2003, of PG&E Corporation;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations, and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

1. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
2. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
3. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting;

5.  The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

1. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
2. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 19, 2003

/S/  Robert D. Glynn, Jr.

Robert D. Glynn, Jr.
Chairman, Chief Executive Officer and President
PG&E Corporation

EXHIBIT 31.1

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Peter A. Darbee, certify that:

1.    I have reviewed this report on Form 10-Q for the quarter ended June 30, 2003, of PG&E Corporation;

2.    Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.    Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations, and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

1. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
2. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
3. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting;

5.    The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

1. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
2. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 19, 2003

/S/  Peter A. Darbee

Peter A. Darbee
Senior Vice President and Chief Financial Officer
PG&E Corporation

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Gordon R. Smith, certify that:

1.  I have reviewed this quarterly report on Form 10-Q for the quarter ended June 30, 2003 of Pacific Gas and Electric Company;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

1. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
2. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
3. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.  The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

1. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
2. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 19, 2003

/S/  Gordon R. Smith

Gordon R. Smith
President and Chief Executive Officer
Pacific Gas and Electric Company

EXHIBIT 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Kent M. Harvey, certify that:

1.  I have reviewed this report on Form 10-Q for the quarter ended June 30, 2003 of Pacific Gas and Electric Company;

2.  Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.  Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.  The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

1. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
2. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
3. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.  The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

1. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
2. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 19, 2003

/S/  Kent M. Harvey

Kent M. Harvey
Senior Vice President - Chief Financial Officer and Treasurer
Pacific Gas and Electric Company

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended June 30, 2003, I, Robert D. Glynn, Jr., Chairman, Chief Executive Officer and President of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended June 30, 2003, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended June 30, 2003, fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

/S/  Robert D. Glynn, Jr.

ROBERT D. GLYNN, JR.
Chairman, Chief Executive Officer and President

August 19, 2003

A signed original of this written statement required by Section 906 has been provided to PG&E Corporation and will be retained by PG&E Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended June 30, 2003, I, Peter A. Darbee, Senior Vice President and Chief Financial Officer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended June 30, 2003, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended June 30, 2003, fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

/S/  Peter A. Darbee

PETER A. DARBEE
Senior Vice President and
Chief Financial Officer

August 19, 2003

A signed original of this written statement required by Section 906 has been provided to PG&E Corporation and will be retained by PG&E Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2003, I, Gordon R. Smith, President and Chief Executive Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2003, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2003, fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/S/  Gordon R. Smith

GORDON R. SMITH
President and Chief Executive Officer

August 19, 2003

A signed original of this written statement required by Section 906 has been provided to Pacific Gas and Electric Company and will be retained by Pacific Gas and Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2003, I, Kent M. Harvey, Senior Vice President, Chief Financial Officer and Treasurer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1)	such Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2003, fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	the information contained in such Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2003, fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/S/  Kent M. Harvey

KENT M. HARVEY
Senior Vice President, Chief Financial Officer
and Treasurer

August 19, 2003

A signed original of this written statement required by Section 906 has been provided to Pacific Gas and Electric Company and will be retained by Pacific Gas and Electric Company and furnished to the Securities and Exchange Commission or its staff upon request.