Exhibit 99.3

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2005

OR

o	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			PG&E Corporation
77 Beale Street			One Market, Spear Tower
P.O. Box 770000			Suite 2400
San Francisco, California 94177			San Francisco, California 94105


Address of principal executive offices, including zip code

Pacific Gas and Electric Company				PG&E Corporation
(415) 973-7000				(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 ý

No o

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

Yes ý

No o

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

Common Stock Outstanding, April 28, 2005:
PG&E Corporation		370,087,968 shares (excluding 24,665,500 shares held by
		a wholly owned subsidiary)
Pacific Gas and Electric Company		Wholly owned by PG&E Corporation

PART I. FINANCIAL INFORMATION
ITEM 1: CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions, except per share amounts)	2005			2004
Operating Revenues
Electric	$	1,660		$	1,791
Natural gas	1,009			931
Total operating revenues	2,669			2,722
Operating Expenses
Cost of electricity	396			561
Cost of natural gas	620			578
Operating and maintenance	767			816
Recognition of regulatory assets	—			(4,900		)
Depreciation, amortization and decommissioning	385			312
Reorganization professional fees and expenses	—			2
Total operating (gain) expenses	2,168			(2,631		)
Operating Income	501			5,353
Reorganization interest income	—			8
Interest income	21			6
Interest expense	(161		)	(231		)
Other expense, net	(1		)	(27		)
Income Before Income Taxes	360			5,109
Income tax provision	142			2,076
Net Income	$	218		$	3,033
Weighted Average Common Shares Outstanding, Basic	388			393
Net Earnings Per Common Share, Basic	$	0.55		$	7.36
Net Earnings Per Common Share, Diluted	$	0.54		$	7.15
Dividends Declared Per Common Share	$	0.30		$	—

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	Balance At
(in millions)	March 31, 2005			December 31, 2004
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,381		$	972
Restricted cash	1,858			1,980
Accounts receivable:
Customers (net of allowance for doubtful accounts of $88 million in 2005 and $93 million in 2004)	1,916			2,085
Regulatory balancing accounts	968			1,021
Inventories:
Gas stored underground	83			175
Materials and supplies	131			129
Prepaid expenses and other	55			46
Total current assets	6,392			6,408
Property, Plant and Equipment
Electric	21,689			21,519
Gas	8,574			8,526
Construction work in progress	518			449
Other	15			15
Total property, plant and equipment	30,796			30,509
Accumulated depreciation	(11,728		)	(11,520		)
Net property, plant and equipment	19,068			18,989
Other Noncurrent Assets
Regulatory assets	6,412			6,526
Nuclear decommissioning funds	1,627			1,629
Other	938			988
Total other noncurrent assets	8,977			9,143
TOTAL ASSETS	$	34,437		$	34,540

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	Balance At
(in millions, except share amounts)	March 31, 2005			December 31, 2004
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	—		$	300
Long-term debt, classified as current	457			758
Rate reduction bonds, classified as current	290			290
Energy recovery bonds, classified as current	197			—
Accounts payable:
Trade creditors	500			762
Disputed claims and customer refunds	2,142			2,142
Regulatory balancing accounts	574			369
Other	499			352
Interest payable	432			461
Income taxes payable	388			185
Deferred income taxes	374			394
Other	879			905
Total current liabilities	6,732			6,918
Noncurrent Liabilities
Long-term debt	6,722			7,323
Rate reduction bonds	506			580
Energy recovery bonds	1,691			—
Regulatory liabilities	3,869			4,035
Asset retirement obligations	1,325			1,301
Deferred income taxes	3,490			3,531
Deferred tax credits	119			121
Preferred stock of subsidiary with mandatory redemption provisions (redeemable, 6.30% and 6.57%, outstanding 4,800,000 shares, due 2005-2009)	120			122
Other	1,756			1,690
Total noncurrent liabilities	19,598			18,703
Commitments and Contingencies (Notes 1, 2, and 7)
Preferred Stock of Subsidiaries	286			286
Preferred Stock
Preferred stock, no par value, 80,000,000 shares, $100 par value, 5,000,000 shares, none issued	—			—
Common Shareholders’ Equity
Common stock, no par value, authorized 800,000,000 shares, issued 393,170,435 common and 1,400,062 restricted shares in 2005 and 417,014,431 common and 1,601,710 restricted shares in 2004	6,196			6,518
Common stock held by subsidiary, at cost, 24,665,500 shares	(718		)	(718		)
Unearned compensation	(31		)	(26		)
Accumulated earnings	2,379			2,863
Accumulated other comprehensive loss	(5		)	(4		)
Total common shareholders’ equity	7,821			8,633
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	34,437		$	34,540

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2005			2004
Cash Flows From Operating Activities
Net income	$	218		$	3,033
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and decommissioning	385			312
Recognition of regulatory assets	—			(4,900		)
Deferred income taxes and tax credits, net	(63		)	1,926
Other deferred charges and noncurrent liabilities	(45		)	237
Tax benefit on employee stock options exercises	25			—
Gain on sale of assets	—			(16		)
Net effect of changes in operating assets and liabilities:
Accounts receivable	169			352
Inventories	90			82
Accounts payable	(115		)	(257		)
Accrued taxes	202			65
Regulatory balancing accounts, net	254			(53		)
Other working capital	(182		)	287
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	—			(20		)
Other, net	14			(33		)
Net cash provided by operating activities	952			1,015
Cash Flows From Investing Activities
Capital expenditures	(349		)	(342		)
Net proceeds from sale of assets	11			18
Decrease (increase) in restricted cash	122			(7,045		)
Other, net	26			(65		)
Net cash used in investing activities	(190		)	(7,434		)
Cash Flows From Financing Activities
Net repayments under credit facilities and short-term borrowings	(300		)	—
Proceeds from issuance of long-term debt, net of issuance costs of $153 million in 2004	—			6,547
Proceeds from issuance of energy recovery bonds, net of issuance costs of $14 million in 2005	1,874			—
Long-term debt matured, redeemed or repurchased	(902		)	(310		)
Rate reduction bonds matured	(74		)	(74		)
Preferred stock with mandatory redemption provisions redeemed	(2		)	—
Common stock issued	120			58
Common stock repurchased	(1,065		)	—
Preferred dividends paid	(4		)	—
Net cash (used in) provided by financing activities	(353		)	6,221
Net change in cash and cash equivalents	409			(198		)
Cash and cash equivalents at January 1	972			3,658
Cash and cash equivalents at March 31	$	1,381		$	3,460
Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	6		$	8
Cash paid for:
Interest (net of amounts capitalized)	267			197
Income taxes refunded, net	(14		)	—
Reorganization professional fees and expenses	—			5
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	111			—
Transfer of liabilities and other payables subject to compromise to operating assets and liabilities	$	—		$	(257	)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2005			2004
Operating Revenues
Electric	$	1,660		$	1,791
Natural gas	1,009			931
Total operating revenues	2,669			2,722
Operating Expenses
Cost of electricity	396			561
Cost of natural gas	620			578
Operating and maintenance	773			808
Recognition of regulatory assets	—			(4,900		)
Depreciation, amortization and decommissioning	385			311
Reorganization professional fees and expenses	—			2
Total operating (gain) expenses	2,174			(2,640		)
Operating Income	495			5,362
Reorganization interest income	—			8
Interest income	20			3
Interest expense	(154		)	(213		)
Other income, net	4			13
Income Before Income Taxes	365			5,173
Income tax provision	142			2,099
Net Income	223			3,074
Preferred dividend requirement	4			8
Income Available for Common Stock	$	219		$	3,066

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	Balance At
	March 31,			December 31,
(in millions)	2005			2004
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,056		$	783
Restricted cash	1,857			1,980
Accounts receivable:
Customers (net of allowance for doubtful accounts of $88 million in 2005 and $93 million in 2004)	1,916			2,085
Related parties	2			2
Regulatory balancing accounts	968			1,021
Inventories:
Gas stored underground and fuel oil	83			175
Materials and supplies	131			129
Prepaid expenses and other	54			43
Total current assets	6,067			6,218
Property, Plant and Equipment
Electric	21,689			21,519
Gas	8,574			8,526
Construction work in progress	518			449
Total property, plant and equipment	30,781			30,494
Accumulated depreciation	(11,715		)	(11,507		)
Net property, plant and equipment	19,066			18,987
Other Noncurrent Assets
Regulatory assets	6,412			6,526
Nuclear decommissioning funds	1,627			1,629
Other	892			942
Total other noncurrent assets	8,931			9,097
TOTAL ASSETS	$	34,064		$	34,302

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	Balance At
	March 31,			December 31,
(in millions, except share amounts)	2005			2004
	(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short term borrowings	$	—		$	300
Long-term debt, classified as current	457			757
Rate reduction bonds, classified as current	290			290
Energy recovery bonds, classified as current	197			—
Accounts payable:
Trade creditors	500			762
Disputed claims and customer refunds	2,142			2,142
Related parties	20			20
Regulatory balancing accounts	574			369
Other	484			337
Interest payable	426			461
Income taxes payable	322			102
Deferred income taxes	351			377
Other	741			869
Total current liabilities	6,504			6,786
Noncurrent Liabilities
Long-term debt	6,442			7,043
Rate reduction bonds	506			580
Energy recovery bonds	1,691			—
Regulatory liabilities	3,869			4,035
Asset retirement obligations	1,325			1,301
Deferred income taxes	3,587			3,629
Deferred tax credits	119			121
Preferred stock with mandatory redemption provisions (redeemable, 6.30% and 6.57%, outstanding 4,800,000 shares, due 2005-2009)	120			122
Other	1,625			1,555
Total noncurrent liabilities	19,284			18,386
Commitments and Contingencies (Notes 1, 2 and 7)
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 299,291,477 shares	1,496			1,606
Common stock held by subsidiary, at cost, 19,481,213 shares	(475		)	(475		)
Additional paid-in capital	1,900			2,041
Reinvested earnings	5,066			5,667
Accumulated other comprehensive loss	(5		)	(3		)
Total shareholders’ equity	8,276			9,130
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	34,064		$	34,302

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2005			2004
Cash Flows From Operating Activities
Net income	$	223		$	3,074
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and decommissioning	385			311
Recognition of regulatory assets	—			(4,900		)
Deferred income taxes and tax credits, net	(70		)	2,014
Other deferred charges and noncurrent liabilities	(49		)	279
Gain on sale of assets	—			(16		)
Net effect of changes in operating assets and liabilities:
Accounts receivable	169			353
Inventories	90			82
Accounts payable	(115		)	(256		)
Accrued taxes	220			98
Regulatory balancing accounts, net	254			(53		)
Other working capital	(179		)	253
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	—			(20		)
Other, net	10			(84		)
Net cash provided by operating activities	938			1,135
Cash Flows From Investing Activities
Capital expenditures	(349		)	(342		)
Net proceeds from sale of assets	11			18
Decrease (increase) in restricted cash	123			(7,043		)
Other, net	26			(65		)
Net cash used in investing activities	(189		)	(7,432		)
Cash Flows From Financing Activities
Net repayments under credit facilities and short-term borrowings	(300		)	—
Proceeds from issuance of long-term debt, net of issuance costs of $153 million in 2004	—			6,547
Proceeds from issuance of energy recovery bonds, net of issuance costs of $14 million in 2005	1,874			—
Long-term debt matured, redeemed or repurchased	(900		)	(310		)
Rate reduction bonds matured	(74		)	(74		)
Common stock dividends paid	(110		)	—
Preferred dividends paid	(4		)	—
Preferred stock with mandatory redemption provisions redeemed	(2		)	—
Common stock repurchased	(960		)	—
Net cash (used in) provided by financing activities	(476		)	6,163
Net change in cash and cash equivalents	273			(134		)
Cash and cash equivalents at January 1	783			2,979
Cash and cash equivalents at March 31	$	1,056		$	2,845
Supplemental disclosures of cash flow information
Cash received for:
Reorganization interest income	$	6		$	8
Cash paid for:
Interest (net of amounts capitalized)	169			175
Income taxes paid, net	—			—
Reorganization professional fees and expenses	—			5
Supplemental disclosures of noncash investing and financing activities
Equity contribution for settlement of POR payable	—			(128		)
Transfer of liabilities and other payables subject to compromise to operating assets and liabilities	$	—		$	(257	)

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: GENERAL

Organization and Basis of Presentation

PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, electricity transmission, and natural gas procurement, transportation and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation.

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 Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include its accounts and those of its wholly owned and controlled subsidiaries, and variable interest entities for which it is subject to a majority of the risk of loss or gain. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying interim unaudited Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles in the United States of America, or GAAP, for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they may not contain all of the information and footnotes required by GAAP for complete financial statements. Both PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets at December 31, 2004, were derived from the audited Consolidated Balance Sheets included in their combined 2004 Annual Report on Form 10-K, or Annual Report, filed with the Securities and Exchange Commission, or SEC.

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

During the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, PG&E Corporation’s and the Utility’s Consolidated Financial Statements were presented in accordance with the American Institute of Certified Public Accountants’ Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” or SOP 90-7. Under SOP 90-7, professional fees and expenses directly related to the Utility’s Chapter 11 proceeding and interest income on funds accumulated during the Chapter 11 proceedings were reported separately as reorganization items. The Utility discontinued the application of SOP 90-7 upon its emergence from Chapter 11 on April 12, 2004 when the Utility’s plan of reorganization under Chapter 11 became effective, or the Effective Date. As discussed below, in Note 2, the U.S. Bankruptcy Court for the Northern District of California, which oversaw the Utility’s Chapter 11 proceeding, retains jurisdiction, among other things, to resolve the remaining disputed claims made in the Utility’s Chapter 11 proceeding.

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 2004 Annual Report.

Earnings Per Common Share

Earnings per common share is calculated, utilizing the “two-class” method, by dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period. In applying the “two-class” method, undistributed earnings are allocated to both common shareholders and participating securities. PG&E Corporation’s $280 million of 9.50% Convertible Subordinated Notes due 2010, or Convertible Subordinated Notes, are entitled to receive (non-cumulative) dividend payments without exercising the conversion option and meet the criteria of a participating security.

The Convertible Subordinated Notes are convertible at the option of the holders into 18,558,655 common shares. All PG&E Corporation’s participating securities participate on a 1:1 basis in dividends with common shareholders.

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

	Three Months Ended
	March 31,
(in millions, except share amounts)	2005		2004

Net income	$	218	$	3,033
Less: distributed earnings to common shareholders	111		—
Undistributed earnings	107		3,033

Common shareholders earnings
*Basic*
Distributed earnings to common shareholders	111		—
Undistributed earnings allocated to common shareholders	102		2,893
Total common shareholders earnings, basic	213		2,893
*Diluted*
Distributed earnings to common shareholders	111		—
Undistributed earnings allocated to common shareholders	102		2,897
Total common shareholders earnings, diluted	$	213	$	2,897

Weighted average common shares outstanding, basic	388		393
9.50% Convertible Subordinated Notes	19		19
Weighted average common shares outstanding and participating securities, basic	407		412

Weighted average common shares outstanding, basic	388		393
Employee stock options, restricted stock and PG&E Corporation shares held by grantor trusts	4		7
PG&E Corporation warrants	—		4
Rounding	—		1
Weighted average common shares outstanding, diluted	392		405
9.50% Convertible Subordinated Notes	19		19
Weighted average common shares outstanding and participating securities, diluted	411		424

Net earnings per common share, basic
Distributed earnings, basic	$	0.29	$	—
Undistributed earnings, basic	0.26		7.36
Total	$	0.55	$	7.36

Net earnings per common share, diluted
Distributed earnings, diluted	$	0.28	$	—
Undistributed earnings, diluted	0.26		7.15
Total	$	0.54	$	7.15

Options to purchase 6,500 and 8,542,006 PG&E Corporation common shares were outstanding during the three months ended March 31, 2005 and 2004, respectively, but not included in the computation of diluted earnings per common share because the option exercise prices were greater than the average market price.

Related Party Agreements and Transactions

In accordance with various agreements, the Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. These services are priced either at the fully loaded cost (i.e., direct costs and allocations of overhead costs) or at the higher of fully loaded cost or fair market value, depending on the nature of the services. PG&E Corporation also allocates certain other corporate administrative and general costs to the Utility and other subsidiaries using agreed allocation factors, including the number of employees, operating expenses excluding fuel purchases, total assets and other cost allocation methodologies. The Utility purchases natural gas transportation services from Gas Transmission Northwest Corporation, or GTNW, formerly known as PG&E Gas Transmission, Northwest Corporation. GTNW is no longer a related party after the cancellation of PG&E Corporation’s equity interest in National Energy & Gas Transmission, Inc., or NEGT, on the effective date of its plan of reorganization, October 29, 2004. Through July 7, 2003, all significant intercompany transactions with NEGT and its subsidiaries were eliminated in consolidation; therefore, no profit or loss resulted from these transactions. Beginning July 8, 2003, the Utility’s transactions with NEGT are no longer eliminated in consolidation. The Utility’s significant related party transactions and related receivable (payable) balances were as follows:

	Three Months Ended				Receivable (Payable) Balance Outstanding at
	March 31,				March 31,			December 31,
(in millions)	2005		2004		2005			2004

Utility revenues from:
Administrative services provided to PG&E Corporation	$	1	$	2	$	1		$	1
Utility expenses from:
Administrative services received from PG&E Corporation	$	25	$	22	$	(20	)	$	(20	)
Interest accrued on pre-petition liabilities due to PG&E Corporation	—		2		—			—
Natural gas transportation services received from GTNW	—		15		—			—

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

Regulation and Statement of Financial Accounting Standards No. 71

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No. 71,”Accounting for the Effects of Certain Types of Regulation,” as amended, or SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the costs of providing service. The Utility is regulated by the CPUC, the FERC and the Nuclear Regulatory Commission, or NRC, among others. SFAS No. 71 applies to all of the Utility’s operations except for the operations of a natural gas pipeline.

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

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

Regulatory Assets

Regulatory assets comprise the following:

	Balance At
	March 31,		December 31,
(in millions)	2005		2004

Settlement Regulatory Asset	$	1,282	$	3,188
Energy recovery bond regulatory asset	1,868		—
Utility retained generation regulatory assets	1,161		1,181
Rate reduction bond assets	676		741
Regulatory assets for deferred income tax	500		490
Unamortized loss, net of gain, on reacquired debt	340		345
Environmental compliance costs	227		192
Post-transition period contract termination costs	139		142
Regulatory assets associated with plan of reorganization	170		182
Other, net	49		65
Total regulatory assets	$	6,412	$	6,526

In light of the satisfaction of various conditions to the implementation of the Utility’s plan of reorganization, the accounting probability standard required to be met under SFAS No. 71 in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement (as described in Note 2) was met as of March 31, 2004. Therefore, the Utility recorded the $3.7 billion, pre-tax ($2.2 billion, after-tax), regulatory asset established under the Settlement Agreement, or the Settlement Regulatory Asset, and $1.2 billion, pre-tax ($0.7 billion, after-tax), for the Utility retained generation regulatory assets in the first quarter of 2004 (see Note 2 for further discussion). As of December 31, 2004, the Utility had recorded pre-tax offsets to the Settlement Regulatory Asset of approximately $309 million ($183 million, after-tax) for supplier settlements and approximately $233 million ($138 million, after-tax) for amortization of the Settlement Regulatory Asset. For the three months ended March 31, 2005, the Utility recorded amortization of the Settlement Regulatory Asset of approximately $33 million ($20 million, after-tax) and did not record any offsets for supplier settlements.

On February 10, 2005, PG&E Energy Recovery Funding, LLC, or PERF, a limited liability company wholly-owned and consolidated by the Utility (but legally separate from the Utility), issued the first series of energy recovery bonds, or ERBs, for approximately $1.9 billion to refinance the remaining after-tax balance of the Settlement Regulatory Asset. As a result of the issuance of ERBs, the pre-tax Settlement Regulatory Asset has been reduced to approximately $1.3 billion (representing the deferred tax liability associated with the collection of the revenues for the ERBs) and the Utility has recorded a regulatory asset related to the ERBs of approximately $1.9 billion.

The Utility’s rate reduction bond asset represents electric industry restructuring costs that the Utility expects to collect over the life of the bonds. The regulatory assets for deferred income tax represent deferred income tax benefits that have already been passed through to customers and are offset by deferred income tax liabilities. The regulatory asset related to unamortized loss, net of gain, on reacquired debt represents costs on debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. Environmental compliance costs are costs incurred by the Utility for environmental remediation. The post-transition period contract termination costs represent amounts the Utility incurred in terminating a 30-year power purchase agreement. Regulatory assets associated with the plan of reorganization include costs incurred in financing the Utility’s exit from Chapter 11 and costs to oversee the environmental enhancement of the Pacific Forest and Watershed Stewardship Council, an entity that was established pursuant to the Utility’s plan of reorganization. These regulatory assets are recoverable from customers in future rates.

In general, the Utility does not earn a return on regulatory assets where the related costs do not accrue interest. Accordingly, the only regulatory asset on which the Utility earns a return are the regulatory assets relating to the Utility’s retained generation and unamortized loss, net of gain on reacquired debt.

The Settlement Agreement authorizes the Utility to earn an 11.22% rate of return on equity on its rate base, including the after-tax amount of the Settlement Regulatory Asset and the retained generation regulatory assets. Now that the remaining unamortized after-tax balance of the Settlement Regulatory Asset has been refinanced through the issuance of the first series of ERBs, the Utility no longer earns this 11.22% rate of return on the Settlement Regulatory Asset as it is no longer a part of rate base.

Regulatory Liabilities

Regulatory liabilities comprise the following:

	Balance At
	March 31,		December 31,
(in millions)	2005		2004

Cost of removal obligation	$	2,000	$	1,990
Asset retirement costs	678		700
Employee benefit plans	640		687
Public purpose programs	198		191
Rate reduction bonds	178		182
Other	175		285
Total regulatory liabilities	$	3,869	$	4,035

The Utility’s regulatory liabilities related to costs of removal represent revenues collected for asset removal costs that the Utility expects to incur in the future. The regulatory liability associated with asset retirement costs represents timing differences between the recognition of nuclear and fossil decommissioning obligations in accordance with GAAP applicable to non-regulated entities under SFAS No. 143, “Accounting for Asset Retirement Obligations,” or SFAS No. 143, and the amounts recognized for ratemaking purposes. The Utility’s regulatory liabilities related to employee benefit plan expenses represent the cumulative differences between expenses recognized for financial accounting purposes and expenses recognized for ratemaking purposes. These balances will be charged against expense to the extent that future financial accounting expenses exceed amounts recoverable for regulatory purposes. The Utility’s regulatory liability related to public purpose programs represents revenues designated for public purpose program costs that are expected to be incurred in the future. The Utility’s regulatory liability for rate reduction bonds represents the deferral of over-collected revenue associated with the rate reduction bonds that the Utility expects to return to customers in the future.

Regulatory Balancing Accounts

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

The Utility expects to collect from or refund to its customers the balances included in current balancing accounts receivable and payable within the next twelve months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next twelve months are included in non-current regulatory assets and liabilities.

Stock-Based Compensation

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

The tables below show the effect on net income and earnings per common share for PG&E Corporation and the Utility had it elected to account for its stock-based compensation plans using the fair-value method under SFAS No. 123 for the three months ended March 31, 2005 and 2004:

	Three Months Ended
	March 31,
(in millions, except per share amounts)	2005			2004

Net earnings:
As reported	$	218		$	3,033
Deduct: Total stock-based employee compensation expense determined under the fair value based method for all awards, net of related tax effects	(3		)	(4		)
Pro forma	$	215		$	3,029

Basic earnings per common share:
As reported	$	0.55		$	7.36
Pro forma	0.55			7.35

Diluted earnings per common share:
As reported	0.54			7.15
Pro forma	0.53			7.14

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

	Three Months Ended March 31,
(in millions)	2005			2004

Net earnings:
As reported	$	219		$	3,066
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects	(2		)	(2		)
Pro forma	$	217		$	3,064

Restricted Stock

At March 31, 2005, a total of 2,418,760 shares of restricted PG&E Corporation common stock had been awarded to eligible employees of PG&E Corporation and its subsidiaries, of which 1,598,140 shares were awarded to Utility employees. PG&E Corporation awarded 329,840 shares of restricted common stock during the three months ended March 31, 2005, of which 242,010 shares were awarded to Utility employees.

The restricted shares are held in an escrow account. The shares become available to the employees as the restrictions lapse. Dividends payable with respect to restricted shares are not paid until the restrictions lapse.

For restricted stock granted in 2003, the restrictions on 80% of the shares lapse automatically over a period of four years at the rate of 20% per year. The compensation expense for these shares remains fixed at the value of the stock at grant date. Restrictions on the remaining 20% of the shares will lapse at a rate of 5% per year if PG&E Corporation is in the top quartile of its comparator group as measured by annual total shareholder return for each year ending immediately before each annual lapse date. The compensation expense recognized for these shares is variable, and changes with the common stock’s market price. As the performance criteria for 2004 were not met, 91,017 shares of restricted stock were forfeited.

Restricted stock awards after 2003 do not contain performance criteria. The restrictions lapse ratably over four years, from the date of award, subject to forfeiture if employment is terminated before the annual vesting date. All restricted shares are also subject to accelerated vesting in certain circumstances, including death, disability, and change in control.

Compensation expense associated with all the shares is recognized on a quarterly basis, by amortizing the unearned compensation related to that period. Total compensation expense resulting from the issuance of restricted shares, as reflected on PG&E Corporation’s Condensed Consolidated Statements of Income, was approximately $3 million for the three months ended March 31, 2005 and approximately $3 million for the three months ended March 31, 2004, of which approximately $2 million for the three months ended March 31, 2005 and approximately $2 million for the three months ended March 31, 2004 was recognized by the Utility. The total unamortized balance of unearned compensation resulting from the issuance of restricted shares, as reflected on PG&E Corporation’s Condensed Consolidated Balance Sheets was approximately $31 million at March 31, 2005 and approximately $26 million at December 31, 2004.

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 Utility’s defined benefit pension plan.

	PG&E Corporation					Utility
(in millions)	2005			2004		2005			2004

Three months ended March 31
Net income available for common stock	$	218		$	3,033	$	219		$	3,066
Net gain in other comprehensive income from current period hedging transactions and price changes in accordance with SFAS No. 133 (net of income tax expense of $2 million in 2004)	—			3		—			3
Minimum pension liability adjustment (net of income tax benefit of $2 million in 2005)	(1		)	—		(2		)	—
Other	—			1		—			—
Comprehensive income	$	217		$	3,037	$	217		$	3,069

Accumulated Other Comprehensive Income (Loss)

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

(in millions)	Hedging Transactions in Accordance with SFAS No. 133			Foreign Currency Translation Adjustment		Minimum Pension Liability Adjustment			Other			Accumulated Other Comprehensive Income (Loss)

Balance at December 31, 2003	$	(81	)	$	—	$	(4	)	$	—		$	(85	)
Period change in:
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133	3			—		—			—			3
Other	—			—		—			1			1
Balance at March 31, 2004	(78		)	—		(4		)	1			(81		)

Balance at December 31, 2004	(1		)	—		(4		)	1			(4		)
Period change in:
Minimum pension liability adjustment	—			—		(1		)	—			(1		)
Other	1			—		—			(1		)	—
Balance at March 31, 2005	$	—		$	—	$	(5	)	$	—		$	(5	)

Accumulated other comprehensive income (loss) included losses related to discontinued operations of approximately $77 million at December 31, 2003. During the fourth quarter of 2004, the remaining losses of approximately $77 million included in accumulated other comprehensive income (loss) were recognized in connection with PG&E Corporation’s elimination of its equity interest in NEGT. Excluding the activity related to NEGT, there was no material difference between PG&E Corporation’s and the Utility’s accumulated other comprehensive income (loss).

Pension and Other Postretirement Benefits

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

Net periodic benefit cost as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income for the three-month period ended March 31, 2005 and March 31, 2004 are as follows:

PG&E Corporation

	Pension Benefits Three Months Ended March 31,						Other Benefits Three Months Ended March 31,
(in millions)	2005			2004			2005			2004

Service cost for benefits earned	$	56		$	47		$	9		$	9
Interest cost	125			118			20			23
Expected return on plan assets	(151		)	(141		)	(21		)	(19		)
Amortization of transition obligation	—			1			6			6
Amortization of prior service cost	14			13			3			3
Amortization of unrecognized loss	6			—			—			—
Net periodic benefit cost	$	50		$	38		$	17		$	22

There was no material difference between the Utility and PG&E Corporation’s net periodic benefit cost.

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

PG&E Corporation and the Utility expect to contribute approximately $20 million for Pension Benefits to fund voluntary retirement program obligations and approximately $68 million for Other Benefits in 2005. These anticipated contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax deductible, consistent with applicable regulatory decisions and sufficient to meet minimum funding requirements. None of these benefit plans are subject to a minimum funding requirement in 2005. The Utility’s pension benefit plans met all the funding requirements under the Employee Retirement Income Security Act of 1974, as amended.

Accounting Pronouncements Issued But Not Yet Adopted

Share-Based Payment Transactions

In December 2004, the FASB issued Statement No. 123 (revised December 2004), “Share-Based Payment,” or SFAS No. 123R. SFAS No. 123R requires that the cost resulting from all share-based payment transactions be recognized in the financial statements and establishes a fair-value measurement objective in determining the value of such a cost. On April 14, 2005, the SEC amended the compliance date and allowed public companies with calendar year-ends to adopt SFAS No. 123R in the first quarter of 2006. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 123R on their Consolidated Financial Statements.

Inventory Costs

In December 2004, the FASB issued Statement No. 151, “Inventory Costs an amendment of ARB No. 43, Chapter 4”, or SFAS No. 151. The guidance clarifies that the allocation of fixed production overhead to inventory is based on normal capacity. Abnormal amounts of idle facility, excess freight, handling costs and spoilage should be recognized as a current period charge. SFAS No. 151 will be effective January 1, 2006. The adoption of SFAS No. 151 is not expected to have a material effect on the financial position or results of operations of either PG&E Corporation or the Utility.

Conditional Asset Retirement Obligations

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations - an interpretation of FASB Statement No. 143,” or FIN 47. FIN 47 clarifies that a conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 will be effective for the fourth quarter of 2005. PG&E Corporation and the Utility are currently evaluating the impact of FIN 47 on their Consolidated Financial Statements.

Restricted Cash Classification on Statement of Cash Flows

PG&E Corporation and the Utility have changed the classification of changes in certain restricted cash balances in their Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2005 and 2004, to present such changes as an investing activity. These changes in restricted cash balances were previously presented as an operating activity.

A summary of the effect of the change in presentation of restricted cash for the three months ended March 31, 2005 and 2004, is as follows:

	As Reported			As Revised
	(in millions)
Three months ended March 31, 2005
PG&E Corporation
Net cash provided by operating activities	$	1,048		952
Net cash used in investing activities	(286		)	(190		)
Utility
Net cash provided by operating activities	1,035			938
Net cash used in investing activities	(286		)	(189		)

Three months ended March 31, 2004
PG&E Corporation
Net cash provided by operating activities	887			1,015
Net cash used in investing activities	(7,306		)	(7,434		)
Utility
Net cash provided by operating activities	1,009			1,135
Net cash used in investing activities		(7,306	)		(7,432	)

NOTE 2: THE UTILITY’S EMERGENCE FROM CHAPTER 11

As a result of the California energy crisis, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 on April 6, 2001. The Utility retained control of its assets and was authorized to operate its business as a debtor-in-possession during its Chapter 11 proceeding. PG&E Corporation and the subsidiaries of the Utility, including PG&E Funding LLC, (which issued rate reduction bonds) and PG&E Holdings LLC (which holds stock of the Utility), were not included in the Utility’s Chapter 11 proceeding.

On April 12, 2004, the Utility emerged from Chapter 11 when its plan of reorganization became effective, or the Effective Date. The plan of reorganization incorporated the terms of the Settlement Agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility’s Chapter 11 proceeding. Although the Utility’s operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the plan of reorganization, and (3) the bankruptcy court’s December 22, 2003 order confirming the plan of reorganization. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims.

In light of the satisfaction of various conditions to the implementation of the plan of reorganization, the accounting probability standard required to be met under SFAS No. 71, in order for the Utility to recognize the regulatory assets provided under the Settlement Agreement was met as of March 31, 2004. Therefore, the Utility recorded the $2.2 billion, after-tax ($3.7 billion, pre-tax) Settlement Regulatory Asset, and $0.7 billion, after-tax ($1.2 billion, pre-tax), for the Utility retained generation regulatory assets. Refer to the 2004 Annual Report for further discussion of the Settlement Agreement. On February 10, 2005, the Utility refinanced the remaining unamortized after-tax portion of the Settlement Regulatory Asset as discussed in Note 4.

As of March 31, 2005, the Utility had accrued approximately $1.6 billion for remaining net disputed claims, consisting of approximately $2.1 billion of accounts payable-disputed claims primarily payable to the California Independent System Operator, or ISO, and the Power Exchange, or the PX, offset by an accounts receivable amount from the ISO and the PX of approximately $0.5 billion. The Utility held $1.6 billion in escrow for the payment of the remaining disputed claims as of March 31, 2005. Upon resolution of these claims and under the terms of the Settlement Agreement, any refunds, claims offsets or other credits that the Utility receives from energy suppliers will be returned to customers. With the approval of the bankruptcy court, the Utility has withdrawn certain amounts from the escrow in connection with settlements with certain ISO and PX sellers.

Petitions for review of the CPUC’s order approving the Settlement Agreement and order denying rehearing of its approval order that had been filed by the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, are still pending at the California Court of Appeal. CCSF and Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF requests that the appellate court hear and review the CPUC’s decisions, approving the Settlement Agreement and Aglet requests that the CPUC’s decisions be overturned. Three California state senators have filed a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not yet acted on the petitions.

In addition, two former CPUC commissioners who did not vote to approve the Settlement Agreement filed an appeal of the bankruptcy court’s confirmation order with the U.S. District Court for the Northern District of California, or the District Court. On July 15, 2004, the District Court dismissed their appeal. The former commissioners have appealed the District Court’s order with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. After briefing is complete, the Ninth Circuit will consider arguments by the Utility and the CPUC to dismiss the appeal. On April 12, 2005, the District Court entered an order dismissing a second appeal of the confirmation order that had been filed by the City of Palo Alto, but which the City of Palo Alto subsequently had agreed to dismiss voluntarily.

PG&E Corporation and the Utility believe the petitions for review of the CPUC orders and the appeal of the confirmation order are without merit and will be rejected. If the bankruptcy court’s confirmation order or the Settlement Agreement is overturned or modified on appeal, PG&E Corporation’s and the Utility’s financial condition and results of operations, and the Utility’s ability to pay dividends or otherwise make distributions to PG&E Corporation, could be materially adversely affected.

NOTE 3: DEBT

Long-Term Debt

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

	Balance At
(in millions)	March 31, 2005			December 31, 2004
PG&E Corporation
Convertible subordinated notes, 9.50%, due 2010	$	280		$	280
Other long-term debt	—			1
Less: current portion	—			(1		)
	280			280

Utility
First mortgage bonds:
3.26% to 6.05% bonds, due 2006-2034	5,300			6,200
Unamortized discount, net of premium	(17		)	(17		)
Total first mortgage bonds	5,283			6,183
Pollution control bond loan agreements, variable rates, due 2007	614			614
Pollution control bond loan agreement, 5.35%, due 2016	200			200
Pollution control bond loan agreements, 3.50%, due 2007	345			345
Pollution control bond reimbursement obligations, variable rates, due 2005	454			454
Other	3			4
Less: current portion	(457		)	(757		)
	6,442			7,043
Total consolidated long-term debt, net of current portion	$	6,722		$	7,323

PG&E Corporation

Convertible Subordinated Notes

PG&E Corporation currently has outstanding $280 million of 9.50% Convertible Subordinated Notes that are scheduled to mature on June 30, 2010. These Convertible Subordinated Notes may be converted (at the option of the holder) at any time prior to maturity into 18,558,655 shares of common stock of PG&E Corporation, at a conversion price of approximately $15.09 per share. The conversion price is subject to adjustment should a significant change occur in the number of PG&E Corporation’s outstanding common shares. To date, the conversion price has not required adjustment. In addition, holders of the Convertible Subordinated Notes are entitled to receive pass-through dividends at the same payout as common stockholders with the number of shares determined by dividing the principal amount of the Convertible Subordinated Notes by the conversion price. On April 15, 2005, PG&E Corporation paid approximately $6 million of pass-through dividends to holders of the Convertible Subordinated Notes. The holders have a one-time right to require PG&E Corporation to repurchase the Convertible Subordinated Notes on June 30, 2007, at a purchase price equal to the principal amount plus accrued and unpaid interest (including liquidated damages and pass-through dividends, if any).

In accordance with SFAS No. 133, the dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be bifurcated from the Convertible Subordinated Notes and marked-to-market on PG&E Corporation’s Consolidated Statements of Income as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation’s Consolidated Balance Sheets at March 31, 2005. At March 31, 2005, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $92 million, of which $20 million is classified as a current liability (in Current liabilities-Other) and $72 million is classified as a noncurrent liability (in Noncurrent liabilities-Other). The change in mark to market fair value for the quarter ended March 31, 2005, was immaterial, and was approximately $32 million, pre-tax, for the quarter ended March 31, 2004.

Utility

First Mortgage Bonds/Senior Notes

On March 23, 2004, the Utility closed a public offering of $6.7 billion of first mortgage bonds, or First Mortgage Bonds. The First Mortgage Bonds were offered in multiple tranches consisting of 3.60% First Mortgage Bonds due March 1, 2009 in the principal amount of $600 million, 4.20% First Mortgage Bonds due March 1, 2011 in the principal amount of $500 million, 4.80% First Mortgage Bonds due March 1, 2014 in the principal amount of $1 billion, 6.05% First Mortgage Bonds due March 1, 2034 in the principal amount of $3 billion, and Floating Rate First Mortgage Bonds due April 3, 2006 in the principal amount of $1.6 billion. The Utility received proceeds of $6.7 billion from the offering, net of a discount of $18 million. The interest rate for the Floating Rate First Mortgage Bonds is based on the three-month London Interbank Offered Rate, or LIBOR, plus 0.70%, which resets quarterly. At March 31, 2005, the interest rate on the Floating Rate First Mortgage Bonds was 3.26%. On April 3, 2005, the rate was reset to 3.82%. The next reset date is July 3, 2005. First Mortgage Bonds in the aggregate amount of $2.5 billion also were used to secure the Utility’s obligations under various other debt agreements.

On October 3, 2004, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $500 million. On January 3, 2005, in anticipation of the receipt of ERB proceeds, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $300 million. On February 24, 2005, the Utility used a portion of the ERB proceeds to defease $600 million of Floating Rate First Mortgage Bonds due in 2006. The defeased bonds were redeemed on April 3, 2005.

The First Mortgage Bonds were secured by a first lien, subject to permitted exceptions, on substantially all of the Utility’s real property and certain tangible personal property related to the Utility’s facilities. The lien was released on April 22, 2005, upon satisfaction of various conditions specified in the indenture, including confirmation from Moody’s Investors Service, or Moody’s, and Standard & Poor’s Ratings Service, or S&P, that the Utility’s unsecured debt ratings following the release would be at least Baa2 from Moody’s and BBB from S&P. On March 3, 2005, Moody’s increased the rating on the First Mortgage Bonds from Baa2 to Baa1. On April 22, 2005, the Utility and the trustee entered into an amended and restated indenture to eliminate the provisions related to the lien of the mortgage. The First Mortgage Bonds have been redesignated as follows:

First Mortgage Bonds	Redesignated As	Amount
3.6% First Mortgage Bonds due 2009	3.6% Senior Notes due 2009	$600 million
4.2% First Mortgage Bonds due 2011	4.2% Senior Notes due 2011	$500 million
4.8% First Mortgage Bonds due 2014	4.8% Senior Notes due 2014	$1 billion
6.05% First Mortgage Bonds due 2034	6.05% Senior Notes due 2034	$3 billion
Floating Rate First Mortgage Bonds due 2006	Floating Rate Senior Notes due 2006	$200 million

Since the lien has been released there is no collateral securing the First Mortgage Bonds and the bonds, now designated as the Senior Notes as set forth in the table above, have become the Utility’s unsecured general obligations ranking pari passu with the Utility’s other unsecured debt. Under the indenture for the Senior Notes, the Utility has agreed that it will not incur secured debt (except for (1) debt secured by specified liens, and (2) secured debt in an amount not exceeding 10% of the Utility’s net tangible assets, as defined in the indenture) unless the Utility provides that the Senior Notes will be equally and ratably secured with the new secured debt.

Pollution Control Bonds

On April 22, 2005, the Utility entered into an amendment to four reimbursement agreements totaling $620 million related to letters of credit aggregating $614 million that had been issued to support certain pollution control bonds issued on behalf of the Utility. In addition to reducing pricing and generally conforming the covenants and events of default to those in

the $1 billion working capital facility (described below), the term of the amended agreements has been extended from three years to five years until April 22, 2010.

Repayment Schedule

At March 31, 2005, PG&E Corporation’s and the Utility’s combined aggregate amounts of scheduled repayments of long-term debt, rate reduction bonds, and ERBs as scheduled are reflected in the table below:

(in millions)	2005			2006			2007			2008			2009			Thereafter			Total

Long-term debt:
PG&E Corporation
Average fixed interest rate	—			—			—			—			—			9.50		%	9.50		%
Fixed rate obligations	$	—		$	—		$	—		$	—		$	—		$	280		$	280
Utility
Average fixed interest rate	—			—			3.50		%	—			3.60		%	5.78		%	5.43		%
Fixed rate obligations	$	—		$	—		$	345		$	—		$	600		$	4,683		$	5,628
Variable interest rate as of March 31, 2005	4.00		%	3.26		%	2.30		%	—			—			—			—
Variable rate obligations	$	454		$	200		$	614		$	—		$	—		$	—		$	1,268
Other	$	2		$	1		$	—		$	—		$	—		$	—		$	3
Total consolidated long-term debt	$	456		$	201		$	959		$	—		$	600		$	4,963		$	7,179
ERBs & RRBs:
Utility
Average fixed interest rate	6.42		%	6.44		%	6.48		%	—			—			—			6.45		%
Rate reduction bonds	$	216		$	290		$	290		$	—		$	—		$	—		$	796
Average fixed interest rate	3.32		%	3.55		%	3.87		%	3.87		%	4.05		%	4.35		%	4.02		%
Energy recovery bonds	$	140		$	221		$	230		$	239		$	248		$	810		$	1,888

Credit Facilities and Short-Term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s short-term borrowings and outstanding credit facilities at March 31, 2005 and December 31, 2004:

	March 31, 2005				December 31, 2004
(in millions)	Revolving Credit Limit		Outstanding		Outstanding

Short-Term Borrowings:
PG&E Corporation
Senior credit facility	$	200	$	—	$	—
Total credit facilities	$	200	$	—	$	—

Utility
Accounts receivable financing	$	650	$	—	$	—
Working capital facility	850		—		300
Total credit facilities	$	1,500	$	—	$	300

	March 31, 2005
Other Credit Facilities:
Utility
Letters of credit (1):
Pollution control bond reimbursement agreements	$	620
Working capital facility	155
Total letters of credit	$	775

First mortgage bonds issued to secure and support various debt and credit facilities (1):
Pollution control bond loan agreements, variable rates, due 2007	$	620
Pollution control bond loan agreement, 5.35%, due 2016	200
Pollution control bond loan agreements, 3.50% variable, due 2007	345
Pollution control bond reimbursement obligations, variable rates, due 2005	454
Working capital facility	850
Total First Mortgage Bonds issued to secure and support various debt and credit facilities	$	2,469

Utility

Working Capital Facility

On April 8, 2005, the Utility entered into a $1 billion revolving credit facility, or the working capital facility. This credit facility replaced the $850 million credit facility that the Utility entered into on March 5, 2004, shortly before the Utility’s plan of reorganization under Chapter 11 became effective. The working capital facility includes a $600 million sublimit for the issuance of letters of credit and a $100 million sublimit for swing line loans. Loans under the working capital facility will be used primarily to cover operating expenses and seasonal fluctuations in cash flows and may also be used for bridge financing in connection with the reissuance of tax-exempt pollution control bonds. Letters of credit under the working capital facility will be used primarily to provide credit enhancements to counterparties for natural gas and electricity procurement transactions.

Subject to obtaining any required regulatory approvals and commitments from existing or new lenders and satisfaction of other specified conditions, the Utility may increase, in one or more requests given not more frequently than once a year, the aggregate lenders’ commitments under the working capital facility by up to $500 million or, in the event that the Utility’s $650 million accounts receivable facility is terminated or expires, by up to $850 million, in the aggregate for all such increases.

The working capital facility has a term of five years and all amounts will be due and payable on April 8, 2010. At the Utility’s request and at the sole discretion of each lender, the facility may be extended for additional periods. The Utility has the right to replace any lender who does not agree to an extension.

The working capital facility includes usual and customary covenants for credit facilities of this type, including covenants limiting liens to those permitted under the Senior Notes indenture, mergers, sales of all or substantially all of the Utility’s assets and other fundamental changes. In addition, the working capital facility also requires that the Utility maintain a debt to capitalization ratio of at most 65% as of the end of each fiscal quarter.

In the event of a default by the Utility under the working capital facility, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $100 million, the lenders may terminate the commitments under the working capital facility and declare the amounts outstanding, including all accrued interest and unpaid fees, payable immediately. The lenders may also enforce all rights and remedies created under applicable law, including set-off rights, and all rights and remedies under the working capital facility. For events of default relating to insolvency, bankruptcy or receivership, the commitments are automatically terminated and the amounts outstanding become payable immediately.

The fees and interest rates the Utility pays under the working capital facility vary depending on the Utility’s unsecured debt rating by S&P and Moody’s. A facility fee based on the total amount of the working capital facility (regardless of the usage) and a utilization fee based on the average daily amount outstanding under the working capital facility are payable quarterly in arrears. The utilization fee is payable during any quarter in which the average daily amount outstanding under the working capital facility is in excess of 50% of the aggregate amount of the facility. At the Utility’s option, any loan under the working capital facility (other than swing line loans) bears interest at a rate equal to the “applicable margin” plus one of the following indexes: (i) LIBOR or (ii) the base rate (the higher of (a) the administrative agent’s base rate and (b) the Federal Funds rate plus 0.50%). Each swing line loan bears interest at the applicable margin plus the base rate. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods.

The facility fee, the utilization fee and the applicable margin are determined in accordance with the following table:

	Applicable Margin for
S&P/Moody’s Rating	Base Rate Loans		LIBOR Loans/Letters of Credit		Facility Fee Rate		Utilization Fee Rate

A/A2 or higher	0	%	0.220	%	0.080	%	0.100	%
A-/A3	0	%	0.300	%	0.100	%	0.100	%
BBB+/Baa1	0	%	0.350	%	0.125	%	0.125	%
BBB/Baa2	0	%	0.425	%	0.150	%	0.125	%
BBB-/Baa3	0	%	0.575	%	0.175	%	0.125	%
BB+/Ba1 or lower	0	%	0.675	%	0.200	%	0.250	%

If the Utility’s debt ratings from S&P and Moody’s are at different levels, the higher rating applies. In addition, the Utility pays a fee for each letter of credit outstanding under the working capital facility equal to the applicable margin for LIBOR loans to be shared by the lenders. The Utility also pays a fronting fee of 0.125% to the issuer of a letter of credit.

At March 31, 2005, there were no loans outstanding under the $850 million working capital facility. The Utility repaid $300 million of loans outstanding under the $850 million working capital facility on February 11, 2005. At March 31, 2005, there were approximately $155 million of letters of credit outstanding under the $850 million working capital facility, which were transferred to the $1 billion working capital facility.

On April 20, 2005, the Utility borrowed $454 million under the working capital facility. The proceeds were used to repay $454 million under certain reimbursement obligations the Utility entered into in April 2004 when its plan of reorganization under Chapter 11 became effective. These reimbursement obligations replaced the Utility’s obligation to certain issuers of letters of credit that were drawn upon during the Chapter 11 proceeding in connection with the redemption of certain pollution control bonds that had been issued for the benefit of the Utility. The Utility anticipates that the draw under its working capital facility will be repaid with the proceeds of a future tax-exempt financing through the issuance of bonds for the benefit of the Utility by the California Infrastructure and Economic Development Bank. The Utility passes on to its customers interest cost savings attributable to the lower interest rates associated with such tax-exempt financing.

NOTE 4: ENERGY RECOVERY BONDS

In connection with the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the unamortized portion of the Settlement Regulatory Asset and associated federal and state income and franchise taxes, in an aggregate principal amount of up to $3.0 billion in two separate series up to one year apart, using a securitized financing supported by a dedicated rate component, or DRC. On February 10, 2005, PERF issued $1.9 billion of ERBs. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as “recovery property,” to be paid a specified amount from a DRC. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility’s electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF.

The aggregate principal amount of the first series of ERBs issued was approximately $1.9 billion. They were issued in five classes, with scheduled maturities ranging from September 25, 2006 to December 25, 2012, and final legal maturities ranging from September 25, 2008 to December 25, 2014. Interest rates on the five classes range from 3.32% for the earliest maturing class to 4.47% for the latest maturing class. The proceeds of the first series of ERBs were paid by PERF to the Utility and were used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset. The proceeds of the second series of ERBs, anticipated to be issued in November 2005 in an aggregate amount of up to $1.1 billion, will be paid by PERF to the Utility to pre-fund the Utility’s recovery through rates of the tax payments that will be due as the Utility collects the DRC over the term of the first series of ERBs to pay principal.

The total principal amount of ERBs outstanding was $1.9 billion at March 31, 2005. The scheduled principal payments on the ERBs for the years 2005 through 2009 are $140 million, $221 million, $230 million, $239 million, and $248 million, respectively. While PERF is a wholly owned consolidated subsidiary of the Utility, PERF is legally separate from the Utility. The assets of PERF (including the recovery property) are not available to creditors of PG&E Corporation or the Utility and the recovery property is not legally an asset of the Utility or PG&E Corporation.

NOTE 5: SHAREHOLDERS’ EQUITY

PG&E Corporation’s and the Utility’s changes in shareholders’ equity for the three months ended March 31, 2005 were as follows:

	PG&E Corporation			Utility
(in millions)	Total Common Shareholders’ Equity			Total Shareholders’ Equity

Balance at December 31, 2004	$	8,633		$	9,130
Net income	218			223
Common stock issued	120			—
PG&E Corporation common stock repurchased:	—			—
Settlement of accelerated share repurchase obligation - February 2005	(14		)	—
Accelerated share repurchase - March 2005	(1,051		)	—
Utility common stock repurchased	—			(960		)
Common restricted stock issued	—			—
Common restricted stock cancelled	—			—
Common restricted stock amortization	3			—
Common stock dividends declared but not yet paid	(111		)	(110		)
Preferred stock dividends	—			(4		)
Tax benefit from employee stock options	25			—
Minimum pension liability adjustment	(1		)	(2		)
Other	(1		)	(1		)
Balance at March 31, 2005	$	7,821		$	8,276

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

March 31, 2005	$	209	$	14	$	195	2	$	92
December 31, 2004	105		7		98		3	62

(1) Gross credit exposure equals mark-to-market value, notes receivable and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity or credit reserves. The Utility’s gross credit exposure includes wholesale activity only. Retail activity and payables are not included. Retail activity at the Utility consists of the accounts receivable from the sale of natural gas and electricity to residential and small commercial customers.

(2) Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

The schedule below summarizes the credit quality of the Utility’s net credit risk exposure to the Utility’s wholesale customers and counterparties at March 31, 2005 and December 31, 2004:

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

Credit Quality ⁽¹⁾

March 31, 2005
Investment grade ⁽³⁾	$	192	98	%
Non-investment grade	3		2	%
Total	$	195	100	%

December 31, 2004
Investment grade ⁽³⁾	$	79	81	%
Non-investment grade	19		19	%
Total	$	98	100	%

(1) Credit ratings are determined by using publicly available information. If provided a guarantee by a higher rated entity (e.g., an affiliate), the rating is determined based on the rating of the guarantor.

(3)Investment grade is determined using publicly available information, i.e., rated at least Baa3 by Moody’s and BBB- by S&P. The Utility has assessed certain governmental authorities that are not rated through publicly available information as investment grade based upon an internal assessment of credit worthiness.

NOTE 7: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments and contingencies in connection with agreements entered into supporting the Utility’s operating activities.

Commitments

PG&E Corporation

For the three months ended March 31, 2005, PG&E Corporation did not have any material new commitments or changes to its material commitments, other than those related to the Utility discussed below. See PG&E Corporation’s and the Utility’s combined 2004 Annual Report for further discussion.

Utility

Power Purchase Agreements

As part of the ordinary course of business, the Utility entered into various agreements to purchase energy and makes payments on existing power purchase agreements. At March 31, 2005, the undiscounted future expected power purchase agreement payments were as follows:

(in millions)

2005	$	1,844
2006	1,975
2007	2,028
2008	1,850
2009	1,638
Thereafter	11,722
Total	$	21,057

Payments made by the Utility under power purchase agreements amounted to approximately $422 million for the three months ended March 31, 2005, and $464 million for the same period in 2004.

Natural Gas Supply and Transportation Commitments

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

At March 31, 2005, the Utility’s obligations for natural gas purchases and gas transportation services were as follows:

(in millions)

2005	$	916
2006	220
2007	7
2008	—
2009	—
Thereafter	—
Total	$	1,143

Payments made by the Utility for natural gas purchases and gas transportation services amounted to approximately $588 million for the three months ended March 31, 2005, and $529 million for the same period in 2004.

Reliability Must Run Agreements

The ISO has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require designated units, known as RMR units, to remain available to generate electricity upon the ISO’s demand when needed for local transmission system reliability. At March 31, 2005, as a party to a Transmission Control Agreement, or TCA, the Utility estimated that it could be obligated to pay the ISO approximately $211 million for costs incurred under these RMR agreements during the period April 1, 2005 to June 30, 2006. Of this amount, the Utility estimates it would receive approximately $21 million under these RMR agreements during the same period. These payments and receipts are subject to applicable ratemaking mechanisms.

In June 2000, a FERC administrative law judge, or ALJ, issued an initial decision addressing subsidiaries of Mirant Corporation. The decision approved rates and a ratemaking methodology that, if affirmed by the FERC, will require the Mirant subsidiaries that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $360 million, including interest, for the availability of RMR plants under these agreements. On July 14, 2003, Mirant Corporation and certain of its subsidiaries filed a petition for reorganization under Chapter 11 and on December 15, 2003, the Utility filed claims in Mirant’s Chapter 11 proceeding including a claim for an RMR refund. On January 14, 2005, the Utility entered into a settlement with Mirant Corporation and its subsidiaries that own RMR units that, among other matters, will resolve the Utility’s claim through September 30, 2004. The settlement agreement is described below. In its order approving the settlement agreement issued April 13, 2005, the FERC terminated the Mirant RMR rate case without deciding the merits of the June 2000 initial decision. The Utility will seek rehearing of only that part of the order terminating the RMR case.

In November 2001, after the ALJ issued the initial decision in the Mirant subsidiaries’ rate case, two complaints were filed at the FERC against other RMR plant owners, including the Utility, alleging that the ratemaking methodology approved in the ALJ’s initial decision should be applied to the other RMR agreements. The complainants asked the FERC to

take no action until after the FERC issues its final decision in the Mirant subsidiaries’ rate case. If the FERC adopted the ALJ’s decision and applied the ratemaking methodology to the Utility’s RMR plants, the Utility could have been required to refund payments it had received from the ISO for the availability of the Utility’s RMR plants. However, on March 23, 2005, the FERC approved a settlement between the Utility and all the complainants that resulted in the withdrawal of the complaint with no decision by the FERC on its merits.

Other Commitments and Operating Leases

The Utility has other commitments relating to operating leases, capital infusion agreements, equipment replacements, the self-generation incentive program exchange agreements and telecommunication contracts. At March 31, 2005, the future minimum payments related to other commitments were as follows:

(in millions)

2005	$	136
2006	47
2007	17
2008	14
2009	6
Thereafter	14
Total	$	234

Payments made by the Utility for other commitments amounted to approximately $17 million for the three months ended March 31, 2005, and $23 million for the same period in 2004.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain NEGT indemnity obligations issued to the purchaser of an NEGT subsidiary company during 2000, up to $150 million. The underlying indemnity obligations of NEGT have expired and PG&E Corporation’s sole remaining exposure relates to the potential of environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser. PG&E Corporation has never received any claims nor does it consider it probable any claims will occur under the guarantee. Accordingly, PG&E Corporation has made no provision for this guarantee at March 31, 2005.

PG&E Corporation also retains a guarantee of the Utility’s underlying obligation to pay workers’ compensation claims. As of March 31, 2005, the actuarially determined workers’ compensation liability was approximately $226.7 million.

Utility

PX Block-Forward Contracts

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

California Energy Crisis Proceedings

FERC Proceedings

Various entities, including the Utility and the state of California are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers for the period May 2000 to June 2001 through a proceeding pending at the FERC and in the appellate courts reviewing FERC decisions. This proceeding, the Refund Proceeding, commenced on August 2, 2000 when a complaint was filed against all suppliers in the ISO and PX markets. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the refunds but asserted that it could not order market-wide refunds for periods before October 2, 2000. In December 2002, a

FERC ALJ issued an initial decision in the Refund Proceeding finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001, but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

In March 2003, the FERC confirmed most of the ALJ’s findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In March, 2005 FERC extended the time for review of gas allowance claims by four months. The FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed) to make compliance filings establishing refund amounts. The ISO has indicated that it plans to make its compliance filing during the fourth quarter of 2005 with the PX to follow but these filings may be delayed until later in 2005 by an extension granted by FERC for submission of gas allowance claims. In October 2003, the FERC affirmed its March 2003 decision and various parties appealed to the Ninth Circuit. Briefs have been submitted concerning which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds. These matters were argued before the Ninth Circuit on April 12 and 13, 2005, and a decision is expected in the following months.

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

In the FERC’s separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, the FERC has asserted that it has the power to order power suppliers to disgorge any profits if the FERC finds that the tariffs in force at that time were violated or subject to manipulation. In September 2004, the Ninth Circuit found that the FERC has the authority to provide refunds for tariff violations involving inadequate transaction reporting for sales into the California spot markets throughout the period before October 2, 2000. The FERC has not yet acted on this finding and it is uncertain how it will be applied by the FERC.

The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as disputed claims. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. Under a bankruptcy court order, the aggregate allowable amount of ISO, PX and generator claims was limited to approximately $1.6 billion. The Utility currently estimates that the claims would have been reduced to approximately $1.0 billion based on the refund methodology recommended in the FERC ALJ’s initial decision. The revised methodology adopted by the FERC’s March 2003 decision could further reduce the amount by several hundred million dollars, offset by the amount of any additional fuel cost allowance for suppliers.

The Utility has entered into settlements with various power suppliers resolving the Utility’s claims against these power suppliers. With the approval of the bankruptcy court, the Utility has withdrawn the amounts resulting from those settlements from the escrow established on the Effective Date for payment of ISO and PX amounts. As of March 31, 2005, the Utility has recorded offsets to the Settlement Regulatory Asset of approximately $309 million, pre-tax ($183 million, after-tax) in connection with these settlements. The final net after-tax amount of any amounts received by the Utility under future settlements with energy suppliers will be credited to customers, either as a reduction to the principal amount of the second series of ERBs, anticipated to be issued in November 2005, or if refunds are received after the second series of ERBs is issued, as a credit to the balancing account that tracks recovery of the customer costs and benefits related to the ERBs.

Mirant Settlement

In January 2005, the Utility and other parties entered into a settlement agreement with Mirant Corporation and certain of its subsidiaries, or Mirant.

The first part of the two-part settlement is between Mirant and several California parties, including the California Attorney General’s Office, the California Department of Water Resources, or DWR, the CPUC, Southern California Edison, San Diego Gas & Electric Company, and the Utility, or the California Parties, resolving market manipulation claims, including Mirant’s liability for FERC refunds, penalties and civil liabilities arising out of the California energy crisis in 2000 to 2001. Under this portion of the agreement, Mirant will provide the California Parties approximately $320 million in cash equivalents and $175 million of allowed claims in Mirant’s bankruptcy proceeding. Of these amounts, the Utility will receive approximately $130 million in cash equivalents and $40 million in allowed claims. The final cash value of the allowed claims will not be known until the completion of Mirant’s bankruptcy proceeding.

California Department of Water Resources Contracts

Electricity from the DWR allocated contracts provided approximately 28% of the electricity delivered to the Utility’s customers for the three-month period ended March 31, 2005. The DWR purchased the electricity under contracts with various generators. The Utility is responsible for administration and dispatch of the DWR’s electricity procurement contracts allocated to the Utility for purposes of meeting a portion of the Utility’s net open position, which is the portion of the demand of a utility’s customers, plus applicable reserve margins, not satisfied from that utility’s own generation facilities and existing electricity contracts. The DWR remains legally and financially responsible for its electricity procurement contracts.

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

The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

•		After assumption, the Utility’s issuer rating by Moody’s will be no less than A2 and the Utility’s long-term issuer credit rating by S&P will be no less than A;

•		The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

•		The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

Environmental Matters

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

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

The Utility had an undiscounted environmental remediation liability of approximately $408 million at March 31, 2005, and approximately $327 million at December 31, 2004. During the three months ended March 31, 2005, the liability increased by approximately $81 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $408 million accrued at March 31, 2005, includes approximately $101 million related to the pre-closing remediation liability associated with divested generation facilities and approximately $307 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $408 million environmental remediation liability, approximately $143 million has been included in prior rate setting proceedings and the Utility expects that approximately $198 million will be allowable for inclusion in future rates. The

Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

The Utility’s undiscounted future costs could increase to as much as $571 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated. The amount of approximately $571 million does not include an estimate for the cost of remediation at known sites owned or operated in the past by the Utility’s predecessor corporations for which the Utility has not been able to determine whether a liability exists.

Taxation Matters

The Internal Revenue Service, or IRS, has completed its audit of PG&E Corporation’s 1997 and 1998 consolidated federal income tax returns and has assessed additional federal income taxes of approximately $81 million (including interest). PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and currently is discussing these adjustments with the IRS’ Appeals Office. PG&E Corporation does not expect final resolution of these appeals to have a material impact on its financial position or results of operations.

In the fourth quarter of 2003, PG&E Corporation made an advance payment to the IRS of $75 million relating to the 1999 and 2000 audit. The IRS completed its audit of PG&E Corporation’s 1999 and 2000 consolidated federal income tax returns during the third quarter of 2004. As a result of the completion of this audit, PG&E Corporation received a refund from the IRS of $14 million in January of 2005.

The IRS is auditing PG&E Corporation’s 2001 and 2002 consolidated federal income tax returns. They have indicated that they plan to complete their audit and issue a Revenue Agent Report in the second or third quarter of 2005. During their examination, the IRS has issued several proposed adjustments that PG&E Corporation is currently disputing. The IRS adjustments include disallowance of synthetic fuel credits claimed on these tax returns. In addition, the IRS has proposed to disallow a number of deductions, the largest of which is abandonment losses/worthless deductions claimed on the 2002 tax return related to certain NEGT assets. These assets were ultimately transferred to NEGT lenders in the third quarter of 2004. If the IRS includes all of its proposed adjustments in the final Revenue Agent Report, the alleged tax deficiency would approximate $400 million. Of this deficiency, approximately $104 million relates to the synthetic fuel credits. The remaining $296 million is timing in nature and would reverse in future periods, generally in tax years 2003-2004. PG&E Corporation believes that it properly reported these transactions in its tax returns and will contest any IRS assessment.

PG&E Corporation has accrued $52 million associated with NEGT related tax liabilities. In addition, PG&E Corporation has accrued a $49 million liability to cover potential tax obligations relating to non-NEGT issues on outstanding tax audits. The Utility has accrued $63 million to cover potential tax obligations for outstanding tax audits. Considering these reserves, PG&E Corporation does not expect the resolution of these matters to have a material impact on its financial position or results of operations.

In addition, based on preliminary information provided by NEGT, PG&E Corporation anticipates paying approximately $86 million of federal income taxes on NEGT activities through the effective date of NEGT’s plan of reorganization.

All IRS audits of PG&E Corporation’s federal income tax returns prior to 1997 have been closed.

Legal Matters

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

Chromium Litigation

There are 14 civil suits pending against the Utility in several California state courts in which plaintiffs allege that exposure to chromium at or near the Utility’s compressor stations at Hinkley and Kettleman, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful deaths, or other injury and seek related damages. One of these suits also names PG&E Corporation as a defendant. Currently, there are approximately 1,200 plaintiffs in the

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

OVERVIEW

This is a combined quarterly report of PG&E Corporation and the Utility and includes separate Condensed Consolidated Financial Statements for each of these two entities. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries and a variable interest entity for which it is subject to a majority of the risk of loss or entitled to receive a majority of the entity’s residual returns. This combined Management’s Discussion and Analysis of Financial Condition and Results of Operations, or MD&A, of PG&E Corporation and the Utility should be read in conjunction with these Condensed Consolidated Financial Statements and Notes to the Condensed Consolidated Financial Statements, as well as the MD&A, Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in their combined 2004 Annual Report on Form 10-K, or 2004 Annual Report, filed with the Securities and Exchange Commission, or SEC.

The Utility served approximately 5.0 million electricity distribution customers and approximately 4.1 million natural gas distribution customers at March 31, 2005. The Utility had approximately $34.1 billion in assets at March 31, 2005 and generated revenues of approximately $2.7 billion in the three months ended March 31, 2005. Its revenues are generated mainly through the sale and delivery of electricity and natural gas at regulated rates. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

During the first quarter 2005, the Utility continued to build momentum to implement its strategy to achieve cost and operating efficiencies and operational excellence. The Utility is in the process of identifying specific initiatives to provide better, faster and more cost-effective service to its customers and invest the savings in the business.

Factors Affecting First Quarter 2005 Results of Operation and Financial Condition

During the first quarter 2005, several factors had a significant impact on PG&E Corporation’s and the Utility’s results of operation and financial condition, including:

•		The issuance of approximately $1.9 billion of Energy Recovery Bonds, or ERBs, as described below;

•		Achievement of a 52% equity ratio on which the Utility is entitled to earn its authorized return;

•		The reinstatement of quarterly dividends, repayment of debt, and the repurchase of common stock; and

•		Upgraded credit ratings.

Issuance of Energy Recovery Bonds

The Utility’s plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, incorporated the terms of the Settlement Agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility, and PG&E Corporation on December 19, 2003, to resolve the Utility’s Chapter 11 proceeding, or the Settlement Agreement. In connection with the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized balance of the $2.2 billion, after-tax ($3.7 billion, pre-tax) regulatory asset provided under the Settlement Agreement, or the Settlement Regulatory Asset, and related federal income and state franchise taxes, in an aggregate principal amount of up to $3.0 billion in two separate series up to one year apart, to be secured by a dedicated rate component, or DRC, to be collected from electricity customers as a nonbypassable charge.

On February 10, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company that is wholly owned and consolidated by the Utility (but legally separate from the Utility), issued approximately $1.9 billion of ERBs. The Utility, as servicer, collects and remits DRC charges to PERF to enable PERF to pay the principal and interest on the ERBs. The proceeds of the ERBs were used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset as follows:

•		The repayment of $300 million borrowed by the Utility in December 2004, in anticipation of the receipt of ERB proceeds, under the Utility’s $850 million working capital facility to partially redeem Floating Rate First Mortgage Bonds on January 3, 2005 in the aggregate principal amount of $300 million;

•		The defeasance of $600 million of Floating Rate First Mortgage Bonds on February 24, 2005 followed by a redemption of the defeased bonds on April 3, 2005; and

•		The repurchase of 22,023,283 shares of the Utility’s common stock at $43.59 per share from PG&E Corporation for an aggregate purchase price of $960 million.

Under the Settlement Agreement, the Utility is authorized to earn a rate of return on equity, or ROE, of no less than 11.22% per year on the equity component of its rate base, including the Settlement Regulatory Asset. The Settlement Regulatory Asset was eliminated from rate base when it was refinanced with the proceeds of the issuance of the ERBs. Therefore the Utility no longer earns an 11.22% ROE on the Settlement Regulatory Asset. As a result, the Utility’s first quarter 2005 net income was reduced by approximately $18 million, compared to the same period in 2004, when the Utility earned the 11.22% ROE on the Settlement Regulatory Asset. Net income for 2005 is estimated to be reduced by approximately $100 million, compared to 2004, due to the elimination of the 11.22% ROE on the Settlement Regulatory Asset.

The proceeds of the second series of ERBs, anticipated to be issued in November 2005 in an aggregate amount of up to $1.1 billion, will be paid by PERF to the Utility to pre-fund the Utility’s recovery through rates of the tax payments that will be due as the Utility collects the DRC over the term of the first series of ERBs to pay principal. Until taxes are fully paid, the Utility will compensate customers, computed at the Utility’s authorized rate of return on rate base, for the use of the proceeds. It is estimated that this carrying cost credit associated with the second series of ERBs would be approximately $60 million (based on an approximate aggregate amount of $1 billion) for the first full year that the second series of ERBs is outstanding. The actual amount will depend on the principal amount of the second series of ERBs. The carrying cost credit and the resulting reduction to net income will decline as the taxes are paid, reaching zero in 2012 when the ERBs and related taxes are paid in full.

Achievement of 52% Equity Ratio

The Settlement Agreement provides that the CPUC will set the Utility’s capital structure and authorized ROE in the Utility’s annual cost of capital proceedings in its usual manner; provided that, the authorized ROE shall not be less than 11.22% per year and the authorized equity ratio for ratemaking purposes shall not be less than 52%. In January 2005, the equity component of the Utility’s capital structure grew to 52%, as compared to about 48% during the first quarter of 2004. As a result, the Utility’s equity earnings in the three months ended March 31, 2005, increased by approximately $14 million compared to the same period in 2004.

Under the Settlement Agreement, the Utility is entitled to earn a ROE of 11.22% on an authorized 52% equity ratio until the Utility’s long-term issuer credit ratings are at least A- from Standard & Poor’s Ratings Services (S&P) or A3 from Moody’s Investors Service (Moody’s). As described below, on February 16, 2005, S&P announced that it had upgraded its corporate credit rating on the Utility to BBB from BBB- and on March 3, 2005, Moody’s announced that it had upgraded the Utility’s issuer credit rating to Baa1 from Baa3.

The currently authorized ROE of 11.22% will be in effect until the Utility’s 2006 cost of capital application is approved by the CPUC. The Utility plans to file its 2006 cost of capital application with the CPUC on May 9, 2005 for its electric utility generation and distribution operations and gas distribution operations.

Stock Repurchases and Dividends

With the achievement of a 52% equity ratio, the Utility reinstated the payment of a regular quarterly dividend. In addition, during the three months ended March 31, 2005, the Utility used cash (including the ERB proceeds) in excess of

amounts needed for operations, debt service and repayment, base capital expenditures, and the quarterly dividend, to repurchase common stock. In turn, PG&E Corporation used the cash received from the Utility in the form of dividends and share repurchases to recommence the payment of a regular quarterly dividend and repurchase common stock from shareholders.

On March 4, 2005, PG&E Corporation entered into a new accelerated share repurchase arrangement with Goldman Sachs & Co., or GS&Co, under which PG&E Corporation repurchased 29,489,400 shares of its common stock for an aggregate amount of approximately $1.05 billion, subject to a price adjustment based on the daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement. The repurchase of common stock under this agreement, increased both basic and diluted earnings per share by approximately $0.01 for the three months ended March 31, 2005 and partially offset the negative earnings impact of the refinancing of the Settlement Regulatory Asset as described above.

Weighted average shares outstanding for basic and diluted earnings per share for the three months ended March 31, 2005 reflect the March 4, 2005 retirement of shares repurchased under the accelerated share repurchase arrangement. At March 31, 2005, PG&E Corporation does not have any obligation to GS&Co. related to the price adjustment or any additional payments. Accordingly, no additional shares attributable to the accelerated share repurchase arrangement were treated as outstanding for purposes of calculating diluted earnings per share (see “Liquidity and Financial Resources” below).

Credit Rating Upgrades

On February 16, 2005, S&P announced that it had upgraded the Utility’s corporate credit rating to BBB from BBB-. On March 3, 2005, Moody’s announced that it had upgraded the Utility’s issuer credit rating to Baa1 from Baa3 and upgraded its rating on the Utility’s outstanding preferred stock to Baa3 from Ba2. Moody’s also assigned a Baa3 issuer rating to PG&E Corporation and a rating of Baa3 to PG&E Corporation’s $200 million unsecured bank revolving credit facility.

On April 22, 2005, the lien of the mortgage securing the Utility’s First Mortgage Bonds was released after satisfaction of several conditions, and following confirmation from S&P and Moody’s that the First Mortgage Bonds (now referred to as Senior Notes) would have unsecured long-term debt ratings of BBB by S&P and Baa1 by Moody’s after the lien was released.

FORWARD-LOOKING STATEMENTS

This combined Quarterly Report on Form 10-Q, including the Management’s Discussion and Analysis of Financial Condition and Results of Operations, or the MD&A, contains forward-looking statements that are necessarily subject to various risks and uncertainties the realization or resolution of which are outside of management’s control. These statements are based on current expectations and projections about future events, and assumptions regarding these events and management’s knowledge of facts at the time the statements were made. These forward-looking statements are identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “might,” “will,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. 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:

Appeals of the Utility’s Plan of Reorganization and Settlement Agreement

•		The timing and resolution of the petitions for review that were filed in the California Court of Appeal for the First Appellate District, seeking review of the CPUC’s approval of the Settlement Agreement; and

•		The timing and resolution of the pending appeals of the confirmation order.

Operating Environment

•		Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility’s ability to earn its authorized rate of return;

•		The level and volatility of wholesale electricity and natural gas prices and supplies, the Utility’s ability to manage and respond to the levels and volatility successfully and the extent to which the Utility is able to timely recover increased costs related to such volatility;

•		Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents,

		mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility’s assets or operations or those of third parties on which the Utility relies, and the extent to which the Utility is able to timely recover costs related to such events;

•		Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates, and the extent to which the Utility is able to timely recover its costs in the face of such events;

•		The operation of the Utility’s Diablo Canyon nuclear power plant, or Diablo Canyon, which exposes the Utility to potentially significant environmental costs and capital expenditure outlays and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close Diablo Canyon and purchase electricity from more expensive sources, and the extent to which the Utility is able to timely recover related costs and expenses;

•		Actions of credit rating agencies;

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

•		Acts of terrorism.

Legislative and Regulatory Environment and Pending Litigation

•		The impact of current and future ratemaking actions of the CPUC, including the risk of material differences between forecasted costs used to determine rates and actual costs incurred;

•		Whether the assumptions and forecasts underlying the Utility’s CPUC-approved long-term electricity procurement plan prove to be accurate, the terms and conditions of the generation or procurement commitments the Utility enters into in connection with its plan, the extent to which the Utility is able to recover the costs it incurs in connection with these commitments and the extent to which a failure to perform by any of the counterparties to the Utility’s electricity purchase contracts or the California Department of Water Resources, or DWR, contracts allocated to the Utility’s customers affects the Utility’s ability to meet its obligations or to recover its costs;

•		Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, the U.S. Congress, the CPUC, the FERC, and the Nuclear Regulatory Commission, or the NRC, with regard to the Utility’s allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;

•		The extent to which the CPUC or the FERC delays or denies recovery of the Utility’s costs, including electricity purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons, resulting in write-offs of regulatory balancing accounts;

•		How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC’s decisions permitting the establishment of holding companies for the California investor-owned electric utilities;

•		The terms and conditions under which the CPUC authorizes the Utility to issue debt and equity in the future, and the extent to which the terms and conditions limit the Utility’s ability to issue debt in the future;

•		Whether the Utility is determined to be in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses;

•		Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws,

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Consolidated Statements of Income for the three-month period ended March 31, 2005 and 2004.

	Three Months Ended March 31,
(in millions)	2005			2004

Utility
Electric operating revenues	$	1,660		$	1,791
Natural gas operating revenues	1,009			931
Total operating revenues	2,669			2,722
Cost of electricity	396			561
Cost of natural gas	620			578
Operating and maintenance	773			808
Recognition of regulatory assets	—			(4,900		)
Depreciation, amortization and decommissioning	385			311
Reorganization professional fees and expenses	—			2
Total operating (gain) expenses	2,174			(2,640		)
Operating income	495			5,362
Interest income (1)	20			11
Interest expense	(154		)	(213		)
Other income, net (2)	—			5
Income before income taxes	361			5,165
Income tax provision	142			2,099
Income available for common stock	$	219		$	3,066

PG&E Corporation, Eliminations and Other (3)
Operating revenues	$	—		$	—
Operating expenses	(6		)	9
Operating income (loss)	6			(9		)
Interest income	1			3
Interest expense	(7		)	(18		)
Other income (expense), net (2)	(1		)	(32		)
Income (loss) before income taxes	(1		)	(56		)
Income tax benefit	—			(23		)
Net loss	$	(1	)	$	(33	)

Consolidated Total
Operating revenues	$	2,669		$	2,722
Operating (gain) expenses	2,168			(2,631		)
Operating income	501			5,353
Interest income (1)	21			14
Interest expense	(161		)	(231		)
Other expenses, net (2)	(1		)	(27		)
Income before income taxes	360			5,109
Income tax provision	142			2,076
Net income	$	218		$	3,033

(1) Includes reorganization interest income.

(2) Includes preferred dividend requirement as other expense.

(3) PG&E Corporation eliminates all intercompany transactions in consolidation.

Utility

Under cost of service ratemaking, the Utility’s rates are determined based on its costs of service and are adjusted periodically to reflect changes in sales or demand compared to forecasted sales or demand used in setting rates. The Utility’s electricity and natural gas distribution rates reflect the sum of individual revenue requirement components. Changes in any individual revenue requirement affect customers’ rates and could affect the Utility’s revenues. Pending regulatory proceedings that could result in rate changes and affect the Utility’s revenues are discussed in PG&E Corporation’s and the Utility’s combined 2004 Annual Report and below under “Regulatory Matters.”

The Utility currently faces price and volumetric risk for the portion of intrastate natural gas transportation capacity that is not contracted under fixed reservation charges used by core customers (see further discussion in the Transportation and Storage section under Risk Management Activities of this Management’s Discussion and Analysis). The Utility is also at risk for costs associated with meeting demand and maintaining electric transmission system sufficiency and reliability in the Utility’s service area in excess of amounts allowed in its FERC-authorized transmission owner rates.

Revenues collected on behalf of the DWR and the DWR’s related costs are not included in the Utility’s Consolidated Statements of Operations, reflecting the Utility’s role as a billing and collection agent for the DWR’s sales to the Utility’s customers.

Electric Operating Revenues

The Utility records its electric distribution and generation revenues under cost-of-service revenue requirements approved by the CPUC in the Utility’s 2003 General Rate Case, or GRC. Differences between the authorized revenue requirements and amounts collected by the Utility from customers in rates are tracked in regulatory balancing accounts and are reflected in miscellaneous revenues in the table below.

The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under the DWR allocated contracts, in the most cost-effective way. This requirement, in certain cases, requires the Utility to schedule more electricity than is necessary to meet its retail load and to sell this additional electricity on the open market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. 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.

The following table shows a breakdown of the Utility’s electric operating revenues.

	Three Months Ended March 31,
(in millions)	2005			2004
Electric revenues	$	2,084		$	2,169
DWR pass-through revenue	(446		)	(470		)
Subtotal	1,638			1,699
Miscellaneous	22			92
Total electric operating revenues	$	1,660		$	1,791
Total electricity sales (in Gwh) (1)	19,034			18,870

(1) Includes DWR electricity sales.

The Utility’s electric operating revenues decreased during the three months ended March 31, 2005, by approximately $131 million, or 7%, compared to the same period in 2004, primarily as a result of the following factors:

•

Electric revenues decreased approximately $175 million during the three months ended March 31, 2005, as compared to the same period in 2004 due to lower electricity procurement and transmission costs which are passed through to customers; and

•

Electric operating revenues decreased $76 million as a result of a decrease in the revenue requirement associated with the Settlement Regulatory Asset. As a result of the refinancing of the Settlement Regulatory Asset on February 10, 2005 through issuance of the ERBs, the Utility was no longer authorized to collect this revenue requirement (see further discussion in the Overview to this MD&A and Note 4 of the Notes to the Condensed Consolidated Financial Statements);

The above decreases were partially offset by the following increases to electric operating revenues:

•		The Utility is authorized to collect and remit a DRC from its electricity customers to repay the ERBs until they are fully retired. This DRC charge resulted in an approximately $23 million electric operating revenue increase in the three months ended March 31, 2005, with no similar amount in the same period in 2004; and

•		The approval of the Utility’s 2003 GRC in May 2004 and the final decision in the 2005 cost of capital proceeding in December 2004 resulted in an increase of approximately $105 million in electric operating revenues in the three months ended March 31, 2005, as compared to the same period in 2004.

Cost of Electricity

The Utility’s cost of electricity includes electricity purchase costs and the cost of fuel used by its owned generation facilities, but it excludes costs to operate its owned generation facilities, which are included in operating and maintenance expense. Electricity purchase costs and the cost of fuel used by owned generation facilities are passed through in rates to customers. The following table shows a breakdown of the Utility’s cost of electricity and the total amount and average cost of purchased power, excluding in each case both the cost and volume of electricity provided by the DWR to the Utility’s customers:

	Three Months Ended March 31,
(in millions)	2005			2004
Cost of purchased power	$	452		$	582
Proceeds from surplus sales allocated to the Utility	(100		)	(64		)
Fuel used in own generation	44			43
Total net cost of electricity	$	396		$	561
Average cost of purchased power per kWh	$	0.065		$	0.083
Total purchased power (GWh)	6,985			6,997

During the three months ended March 31, 2005, the Utility’s cost of electricity decreased approximately $165 million, or 29%, compared to 2004, mainly due to the following factors:

•		The decrease in the average cost of purchased power of $0.018 per kWh in 2005 as compared to 2004 resulted in a decrease of approximately $130 million in the cost of purchased power; and

•		The increase in proceeds from surplus sales allocated to the Utility of $36 million in the three months ended March 31, 2005, as compared to the same period in 2004 resulted in a corresponding decrease in the cost of electricity.

Natural Gas Operating Revenues

The Utility sells natural gas and provides natural gas transportation services to its customers. The Utility’s natural gas customers consist of two categories: core and noncore customers. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercial natural gas customers. The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. While the Utility provides non-core customers with delivery service, it does not provide non-core customers with natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. In 2004, core customers represented

over 99% of the Utility’s total customers and approximately 35% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility’s total customers and approximately 65% of its total natural gas deliveries.

The Utility’s transportation system transports gas throughout California to the Utility’s distribution system, which, in turn, delivers gas to end-use customers. Utility transportation and distribution services for all customers have historically been bundled or sold together at a combined rate.

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

	Three Months Ended March 31,
(in millions)	2005		2004
Bundled natural gas revenues	$	944	$	867
Transportation service-only revenues	65		64
Total natural gas operating revenues	$	1,009	$	931
Average bundled revenue per Mcf of natural gas sold	$	8.77	$	7.74
Total bundled natural gas sales (in millions of Mcf)	108		112

The Utility’s natural gas operating revenues increased approximately $78 million, or 8%, during the three months ended March 31, 2005, compared to the same period in 2004. The increase in natural gas operating revenues was primarily due to the following factors:

•		Bundled natural gas revenues (excluding the effects of the 2003 GRC decision discussed below) increased by approximately $57 million, or 7%, in the three months ended March 31, 2005, as compared to the same period in 2004, mainly resulting from a higher cost of natural gas which the Utility is permitted by the CPUC to pass on to its customers through higher rates. The average bundled revenue per thousand cubic feet, or Mcf, of natural gas sold in 2005 (excluding the effects of the GRC decision) increased by approximately $0.85, or 11%, as compared to 2004; and

•		The approval of the 2003 GRC resulted in an increase to natural gas revenues of approximately $20 million in the three months ended March 31, 2005, as compared to the same period in 2004.

Cost of Natural Gas

The Utility’s cost of natural gas includes the purchase cost of natural gas and transportation costs on interstate pipelines, but excludes the costs associated with the Utility’s intrastate pipeline, which are included in operating and maintenance expense. The following table shows a breakdown of the Utility’s cost of natural gas:

	Three Months Ended March 31,
(in millions)	2005		2004
Cost of natural gas sold	$	584	$	542
Cost of natural gas transportation	36		36
Total cost of natural gas	$	620	$	578
Average cost per Mcf of natural gas sold	$	5.41	$	4.84
Total natural gas sold (in millions of Mcf)	108		112

In the three months ended March 31, 2005, the Utility’s total cost of natural gas increased approximately $42 million, or 7%, compared to the same period in 2004 primarily due to an increase in the average market price of natural gas purchased of approximately $0.57 per Mcf.

Operating and Maintenance

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

During the three months ended March 31, 2005, the Utility’s operating and maintenance expenses decreased by approximately $35 million, or 4%, compared to the same period in 2004, mainly due to the following factors:

•		Operating and maintenance expenses decreased approximately $30 million related to the various provisions of the Settlement Agreement, including obligations to invest in clean energy technology and the donation of land, in the first quarter of 2004 with no similar amounts for the same period in 2005;

•		Operating and maintenance expenses decreased approximately $10 million at Diablo Canyon in the three months ended March 31, 2005, as compared to the same period in 2004 reflecting the scheduled refueling outage in the first quarter of 2004 with no similar refueling outage in the same period in 2005;

•		Employee benefit plan-related expenses decreased approximately $20 million in the three months ended March 31, 2005, as compared to the same period in 2004, due to lower interest cost, higher than expected returns on trust assets and the impact of Diablo Canyon reapplying SFAS No. 71 in April 2004. Prior to the reapplication of SFAS No. 71, Diablo Canyon’s expenses impacted net income; there was no similar impact in the three months ended March 31, 2005.

•		These decreases were partially offset by an increase of approximately $30 million in the three months ended March 31, 2005, as compared to the same period in 2004, for environmental matters resulting from reassessments of the estimated liability for various sites.

Recognition of Regulatory Assets

In light of the satisfaction of various conditions to the implementation of the Utility’s plan of reorganization, the Utility recorded the regulatory assets provided for under the Settlement Agreement in the first quarter of 2004. This resulted in the recognition of a one-time non-cash, pre-tax gain of $3.7 billion for the Settlement Regulatory Asset and $1.2 billion for the Utility retained generation regulatory assets, for a total after-tax gain of $2.9 billion

Depreciation, Amortization and Decommissioning

In the three months ended March 31, 2005, the Utility’s depreciation, amortization and decommissioning expenses increased by approximately $74 million, or 24%, compared to the same period in 2004, primarily as a result of the amortization of the Settlement Regulatory Asset and Energy Recovery Bond Regulatory Asset and an increase in the Utility’s plant assets.

Interest Income

In the three months ended March 31, 2005, interest income, including reorganization interest income, increased by approximately $9 million, or 82%, compared to the same period in 2004, primarily due to interest earned on the $1.7 billion disputed escrow cash account in the three months ended March 31, 2005, and higher average interest rates on the Utility’s short-term investments in the three months ended March 31, 2005, compared to the same period in 2004. The Utility discontinued reporting in accordance with SOP 90-7 upon its emergence from Chapter 11 on April 12, 2004. Prior to that date, the Utility reported reorganization interest income separately on its Consolidated Statements of Income. Reorganization interest income reported in 2004 mainly included interest earned on cash accumulated during the Utility’s Chapter 11 proceedings.

Interest Expense

In the three months ended March 31, 2005, the Utility’s interest expense decreased by approximately $59 million, or 28%, compared to the same period in 2004, mainly due to a lower average amount of outstanding debt and a lower weighted average interest rate during the three months ended March 31, 2005, as compared to the same period in 2004.

Income Tax Expense

At March 31, 2005, PG&E Corporation and its subsidiaries had consolidated cash and cash equivalents of approximately $1.4 billion, and restricted cash of approximately $1.9 billion. PG&E Corporation and the Utility maintain separate bank accounts. At March 31, 2005, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $319 million. At March 31, 2005, the Utility had cash and cash equivalents of approximately $1.1 billion, and restricted cash of approximately $1.9 billion. The Utility’s restricted cash includes amounts deposited in escrow related to the remaining disputed Chapter 11 claims, collateral required by the ISO and deposits under certain third party agreements. PG&E Corporation and the Utility primarily invest their cash in money market funds and in short-term obligations of the U.S. Government and its agencies.

The Utility seeks to maintain or strengthen its credit ratings to provide efficient access to financial and trade credit and to ensure adequate liquidity. On February 16, 2005, S&P, upgraded its corporate credit rating on the Utility to BBB from BBB- and affirmed its BBB senior secured rating on the Utility’s First Mortgage Bonds. S&P has not assigned a rating to PG&E Corporation.

On March 3, 2005, Moody’s announced that it had upgraded its corporate credit rating on the Utility to Baa1 from Baa3 and upgraded the Utility’s other debt ratings as follows:

•		First Mortgage Bonds, secured pollution control bonds, and secured bank loan agreement to Baa1 from Baa2;

•		Preferred stock to Baa3 from Ba2;

•		Shelf registration for the issuance of First Mortgage Bonds to (P)Baa1 from (P)Baa2; and

•		The issuance of senior unsecured debt to (P)Baa1 from (P)Baa3.

Moody’s also assigned a rating of Baa3 to PG&E Corporation’s $200 million unsecured bank revolving credit facility. Moody’s stated that its rating outlook is stable for the Utility and PG&E Corporation.

As discussed in Note 3 in the Notes to the Condensed Consolidated Financial Statements, on April 22, 2005, the lien of the indenture securing the First Mortgage Bonds was released following confirmation by Moody’s and S&P that the Utility’s unsecured debt would be rated BBB by S&P and Baa1 by Moody’s after the release of the lien.

PG&E Corporation and the Utility have taken advantage of recent favorable market conditions by completing the following post-March 31 transactions:

•		On April 8, 2005, the Utility refinanced its existing $850 million working capital facility with a $1 billion working capital facility that has a term of 5 years, reduced fees and applicable margins, and less restrictive covenants;

•		On April 22, 2005, the Utility entered into an amendment to four reimbursement agreements totaling $620 million related to letters of credit aggregating $614 million that had been issued to support certain pollution control bonds issued on behalf of the Utility. In addition to containing more favorable provisions, the term of the amended agreements has been extended from three years to five years until April 22, 2010; and

•		On April 8, 2005, PG&E Corporation’s unsecured $200 million credit facility was amended to include an extended 5-year term and to conform the provisions regarding covenants, representations and events of default to those contained in the Utility’s $1 billion working capital facility.

Currently, PG&E Corporation and the Utility have available credit facilities totaling $200 million and $1.65 billion, respectively.

Dividends

On February 16, 2005, the Board of Directors of the Utility declared a dividend of $117 million that was paid on February 17, 2005, to PG&E Corporation and PG&E Holdings LLC, a wholly owned subsidiary of the Utility that held approximately 6% of the Utility’s common stock.

Also, on February 16, 2005, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.30 per share to shareholders of record on March 31, 2005. On April 15, 2005, PG&E Corporation paid this

dividend totaling approximately $118 million, of which approximately $7 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. In addition, PG&E Corporation paid approximately $6 million in dividend equivalent payments to Convertible Subordinated Note holders of record on March 31, 2005.

PG&E Corporation charged dividends declared to Accumulated Earnings and the Utility charged dividends declared to Reinvested Earnings.

Stock Repurchases

On February 22, 2005, under an accelerated share repurchase arrangement entered into on December 15, 2004, PG&E Corporation paid Goldman Sachs & Co., or GS&Co., approximately $14 million as a price adjustment based on the daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement. PG&E Corporation charged the payment to Common Stock within Common Shareholders’ Equity.

On March 4, 2005, PG&E Corporation entered into a new accelerated share repurchase arrangement with GS&Co. under which PG&E Corporation repurchased 29,489,400 shares of its common stock at an initial price of $35.60 per share (for an aggregate amount of approximately $1.05 billion). The repurchase was funded from available cash on hand and the repurchased shares were retired. PG&E Corporation charged approximately $460 million to Common Stock and approximately $591 million to Accumulated Earnings within Common Shareholders’ Equity in respect of these transactions. Under the accelerated share repurchase arrangement, PG&E Corporation may receive from, or be required to pay to, GS&Co. a price adjustment based on the daily volume weighted average market price of PG&E Corporation common stock over the term of the arrangement (approximately six months). Because the price adjustment and any additional payments that PG&E Corporation may be required to make can be settled at PG&E Corporation’s option, in cash or in shares of its common stock, or a combination of the two, PG&E Corporation accounts for its payment obligations as equity.

Until the transaction is completed or terminated, GAAP requires PG&E Corporation to assume that it will issue shares to settle its obligations (up to a maximum of two times the number of shares repurchased or 58,978,800 shares). PG&E Corporation must calculate the number of shares that would be required to satisfy its obligations upon completion of the transaction based on the market price of PG&E Corporation’s common stock at the end of a reporting period. The number of shares that would be required to satisfy the obligations must be treated as outstanding for purposes of calculating diluted earnings per share. At March 31, 2005, PG&E Corporation did not have any net payment obligations to GS&Co. Accordingly, no additional shares of PG&E Corporation common stock attributable to the accelerated share repurchase arrangement were treated as outstanding for purposes of calculating diluted earnings per share. Based upon the average price of PG&E Corporation stock from March 4, 2005 to March 31, 2005, and additional payments, GS&Co. had a net payment obligation to PG&E Corporation of approximately $1 million at March 31, 2005.

On March 8, 2005, the Utility used proceeds from the issuance of ERBs (discussed in Note 4 of the Notes to the Condensed Consolidated Financial Statements) to repay debt and to repurchase 22,023,283 shares of its common stock from PG&E Corporation for an aggregate purchase price of approximately $960 million. The Utility recognized charges of approximately $141 million to Additional Paid-in Capital, approximately $110 million to Common Stock, and approximately $709 million to Reinvested Earnings within Shareholders’ Equity in respect of this transaction.

Utility

Operating Activities

The Utility’s cash flows from operating activities consist of sales to its customers and payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. Cash flows from operating activities are also impacted by collections of accounts receivable and payments of liabilities previously recorded.

The Utility’s cash flows from operating activities for the three months ended March 31, 2005 and 2004 were as follows:

	Three Months Ended March 31,
(in millions)	2005			2004
Net income	$	223		$	3,074
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	385			311
Gain on establishment of regulatory asset, net	—			(2,904		)
Change in accounts receivable	169			353
Change in accrued taxes	220			98
Other uses of cash:
Payments authorized by the bankruptcy court on amounts classified as liabilities subject to compromise	—			(20		)
Other changes in operating assets and liabilities	(59		)	223
Net cash provided by operating activities	$	938		$	1,135

Net cash provided by operating activities decreased by approximately $197 million during the three months ended March 31, 2005 compared to the same period in 2004, mainly due to the decrease in cash provided by operating assets and liabilities of approximately $282 million.

Investing Activities

The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash flows from operating activities have been sufficient to fund the Utility’s capital expenditure requirements during the three month periods ended March 31, 2005 and 2004. Year to year variances depend upon the amount and type of construction activities, which can be influenced by storm and other factors.

The Utility’s cash flows from investing activities for the three month periods ended March 31, 2005 and 2004 were as follows:

	Three Months Ended March 31,
(in millions)	2005			2004
Capital expenditures	$	(349	)	$	(342	)
Net proceeds from sale of assets	11			18
Decrease (increase) in restricted cash	123			(7,043		)
Other investing activities, net	26			(65		)
Net cash used in investing activities	$	(189	)	$	(7,432	)

Net cash used by investing activities decreased by approximately $7.2 billion primarily due to an increase in restricted cash of approximately $7.2 billion for the three months ended March 31, 2004 with no similar change for the same period in 2005. In March 2004, the Utility consummated a public offering of $6.7 billion of first mortgage bonds. Proceeds from this offering and redemption premiums and interest of $217 million were deposited into escrow for payment of claims upon emergence from Chapter 11. On April 12, 2004, the effective date of the Utility’s plan or reorganization, this cash was paid out of the escrow account.

Financing Activities

In 2005, the Utility used the $1.9 billion proceeds of the ERBs to refinance the Settlement Regulatory Asset through the repayment of debt and repurchase of equity.

The Utility’s cash flows from financing activities for the three month period ended March 31, 2005 and 2004 were as follows:

	Three Months Ended March 31,
(in millions)	2005			2004
Net proceeds from long-term debt issued	$	—		$	6,547
Net proceeds from energy recovery bonds issued	1,874			—
Net repayments under credit facilities and short-term borrowings	(300		)	—
Rate reduction bonds matured	(74		)	(74		)
Long-term debt, matured, redeemed or repurchased	(900		)	(310		)
Common stock dividends paid	(110		)
Preferred dividends paid	(4		)	—
Preferred stock with mandatory redemption provisions redeemed	(2		)	—
Common stock repurchased	(960		)	—
Net cash provided by (used in) financing activities	$	(476	)	$	6,163

For the three months ended March 31, 2005, net cash used in financing activities decreased by approximately $6.6 billion compared to the same period in 2004, due to the following factors:

•		In March 2004, in connection with the Utility’s plan of reorganization, the Utility issued approximately $6.5 billion, net of issuance costs, in long-term debt with no comparable amount in the three months ended March 31, 2005;

•		In February 2005, PERF issued approximately $1.9 billion of ERBs with no similar issuance in 2004 (see Note 4 of the Notes to the Condensed Consolidated Financial Statements for further discussion);

•		During the quarter, the Utility repaid $300 million it borrowed under its $850 million working capital facility;

•		In January 2005, the Utility partially redeemed Floating Rate First Mortgage Bonds due in 2006 in the aggregate principal amount of $300 million and on February 24, 2005, the Utility used a portion of the ERBs proceeds to defease $600 million of Floating Rate First Mortgage Bonds. During the first quarter 2004, repayments on long-term debt totaled $310 million. As a result, repayments on long-term debt increased approximately $590 million in the three months ended March 31, 2005, as compared to the same period in 2004;

•		In February 2005, the Utility paid $110 million in common stock dividends to PG&E Corporation and $7 million to PG&E Holdings LLC, a wholly owned subsidiary of the Utility;

•		Approximately $4 million of preferred stock dividends were paid during the three months ended March 31, 2005; and

•		In March 2005, the Utility used proceeds from the issuance of ERBs to repurchase $960 million of its common stock from PG&E Corporation.

PG&E Corporation

As of March 31, 2005, PG&E Corporation had stand-alone cash and cash equivalents of approximately $319 million. PG&E Corporation’s sources of funds are dividends and share repurchases from the Utility, issuance of its common stock and external financing. The Utility paid a cash dividend of $117 million to PG&E Corporation and PG&E Holdings LLC on February 17, 2005. The Utility did not pay any dividends to, nor repurchase shares from, PG&E Corporation during 2004.

Operating Activities

PG&E Corporation’s consolidated cash flows from operating activities consist mainly of billings to the Utility and other affiliates for services rendered and payments for employee compensation and goods and services provided by others to PG&E Corporation. PG&E Corporation also incurs interest costs associated with its debt.

PG&E Corporation’s consolidated cash flows from operating activities for the three months ended March 31, 2005 and 2004 were as follows:

	Three Months Ended March 31,
(in millions)	2005			2004
Net income	$	218		$	3,033
Non-cash (income) expenses:
Depreciation, amortization and decommissioning	385			312
Deferred income taxes and tax credits, net	(63		)	(70		)
Recognition of regulatory asset, net of tax	—			(2,904		)
Other deferred charges and noncurrent liabilities	(45		)	237
Tax benefit from employee stock plans	25			—
Other changes in operating assets and liabilities	432			407
Net cash provided by operating activities	$	952		$	1,015

Net cash provided by operating activities for PG&E Corporation was substantially the same as the Utility for the three months ended March 31, 2005 and 2004.

Investing Activities

On March 8, 2005, PG&E Corporation received $960 million in proceeds for the repurchase of 22,023,283 shares of Utility common stock by the Utility. This transaction was eliminated in consolidation. PG&E Corporation, on a stand-alone basis, did not have any other material investing activities during the three months ended March 31, 2005 or the same period in 2004.

Financing Activities

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

PG&E Corporation’s consolidated cash flows from financing activities for the three months ended March 31, 2005 and 2004 were as follows:

	Three Months Ended March 31,
(in millions)	2005			2004
Net repayments under credit facilities and short-term borrowings	$	(300	)	$	—
Net proceeds from issuance of energy recovery bonds	1,874			—
Net proceeds from issuance of long-term debt	—			6,547
Long-term debt matured, redeemed or repurchased	(901		)	(310		)
Rate reduction bonds matured	(74		)	(74		)
Preferred stock with mandatory redemption provisions redeemed	(2		)	—
Common stock issued	120			58
Common stock repurchased	(1,065		)	—
Preferred dividends paid	(4		)	—
Other, net	(1		)	—
Net cash (used in) provided by financing activities	$	(353	)	$	6,221

PG&E Corporation’s net cash used by financing activities decreased by $6.6 billion for the three months ended March 31, 2005, compared to the same period in 2004. The decrease was primarily related to the Utility’s financing activities as discussed above, PG&E Corporation’s repurchase of approximately 29.5 million shares of common stock under an accelerated share repurchase agreement in March 2005 at an initial purchase price of $1.05 billion, and increased proceeds from common stock issuances due to increased employee stock option exercises in the three months ended March 31, 2005, compared to the same period in 2004. As discussed above, the Utility’s repurchase of its common stock from PG&E Corporation totaling $960 million in March 2005 was eliminated in consolidation.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual obligations and commitments in connection with business activities. These obligations need to be funded in the future and primarily relate to financing arrangements (such as long-term debt, preferred stock and certain forms of regulatory financing), purchases of transportation capacity, natural gas and electricity to support customer demand and the purchase of fuel and transportation to support the Utility’s generation

Electricity Generation Resources

Procurement Cost Balancing Account and Mandatory Rate Adjustments

California law allows the Utility to recover its reasonably incurred wholesale electricity procurement costs. The Utility has established a balancing account, the Energy Resource Recovery Account, or ERRA, to track the difference between the authorized revenue requirement and the actual costs incurred under the Utility’s authorized electricity resource procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs recorded in the ERRA at least semi-annually and adjust retail electricity rates or order refunds, as appropriate, when the forecast aggregate over-collections or under-collections exceed 5% of the Utility’s prior year electricity procurement revenues, excluding amounts collected for the DWR. For 2005, 5% of the Utility’s 2004 electricity procurement revenues, excluding amounts collected for the DWR, is approximately $164.4 million. As of March 31, 2005, the ERRA had an over-collected balance of approximately $82 million, below the amount that would trigger the mandatory adjustment of rates. The CPUC approved an ERRA revenue requirement of $2.14 billion for 2005 based on forecast costs and has authorized the Utility to amortize routine over- and under-collections in the ERRA annually to coincide with January 1 rate changes.

The CPUC performs periodic compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The cost of procurement activities related to the DWR’s allocated contracts could be disallowed up to a maximum of two times the Utility’s administration costs associated with procurement each year. For 2005, this amount is $36 million. On April 21, 2005, the CPUC approved the Utility’s application related to its procurement activities recorded in the ERRA for the period of January 1, 2003 through May 31, 2003, finding that the Utility’s contract administration, least cost dispatch, procurement activities, and generation fuel costs were in compliance with its 2003 updated procurement plan. The Utility expects to receive a draft decision on the remainder of the record period (i.e., June 1, 2003 to December 31, 2003) in the second quarter of 2005. On February 15, 2005, the Utility filed an ERRA compliance review application for the January 1 - December 31, 2004 record period. Final action on the 2004 record period application is expected before the end of 2005. PG&E Corporation and the Utility are unable to predict whether a disallowance will result or the size of any potential disallowance. In addition, it is uncertain whether the CPUC will modify or eliminate the maximum disallowance for future years.

New Long-Term Generation Resource Commitments

In accordance with the Utility’s CPUC-approved long-term electricity procurement plan, the Utility has requested offers from providers of all potential sources of new generation (e.g., conventional or renewable resources to be provided under utility-owned projects or turnkey developments, or buyouts, or under third party power purchase agreements) for approximately 1,200 megawatts, or MW, of peaking resources by 2008 and an additional 1,000 MW of load-following resources by 2010.

Initial bids were submitted in late April 2005. It is anticipated that contracts for the winning bidders will be submitted to the CPUC for approval in the second half of 2005.

DWR Allocated Contracts

The Utility acts as a billing agent for the collection of the DWR’s revenue requirements from the Utility’s customers. The DWR’s revenue requirements consist of a power charge to pay for the DWR’s costs of purchasing electricity under its contracts and a bond charge to pay for the DWR’s costs associated with its $11.3 billion bond offering completed in November 2002. In December 2004, the CPUC issued a decision on the permanent cost allocation methodology for the DWR’s power charge revenue requirements in 2004 and subsequent years, among the three California investor-owned electric utilities. In January 2005, the CPUC granted limited rehearing of its permanent cost allocation decision to address how to calculate the above-market costs of the DWR power contracts. A final decision on DWR permanent cost allocation is expected in the second quarter of 2005. The Utility cannot predict the final outcome of this matter. As a result of the transition from frozen rates and the electricity procurement recovery mechanism described below, the collection of DWR revenue requirements, or any adjustments thereto, should not affect the Utility’s results of operations.

The CPUC is also considering reallocation of certain DWR contracts for operation and dispatch purposes. The Utility is unable to predict the outcome of this proceeding, nor the potential financial impact.

Diablo Canyon Steam Generator Replacement Projects

On February 24, 2005 the CPUC issued an interim decision on the Utility’s Diablo Canyon Steam Generator Replacement Project, or SGRP, application. The interim decision concluded that the SGRP is cost-effective and $706

million, as adjusted for actual inflation and cost of capital, is a reasonable estimate of the SGRP cost. The interim decision also concluded that an after-the-fact reasonableness review of the SGRP cost is not required, but not precluded either. It adopts a maximum allowable SGRP cost cap of $815 million as adjusted for actual inflation and cost of capital, and the Utility will not be allowed to recover SGRP costs in excess of this amount. The Utility will file an advice letter to request authority to implement a rate increase, subject to refund, for each unit at the time each unit begins commercial operations. After installation is complete, and both units are operational, the Utility will be required to file an application to include the costs permanently in rates. The interim decision does not approve or disapprove the SGRP, guarantee or approve the recovery of any expenditures related thereto, or dictate the outcome of the environmental review of the SGRP pursuant to the California Environmental Quality Act, or CEQA. A final decision, which will include the results of the CEQA review, is expected in September 2005. As of March 31, 2005, expenditures on the project of approximately $26.7 million have been incurred. These expenditures are expected to increase to approximately $65 million by September 2005 when the CPUC’s final decision approving the project is expected. If the CPUC approves the project, the Utility estimates it would spend an additional $14.5 million in the last quarter of 2005. If the CPUC does not approve the projects, then the Utility will terminate the contracts and seek to recover the project costs that it incurred before termination from customers through the abandoned project process.

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

On April 4, 2005, the Utility filed a motion with the CPUC seeking approval of a settlement agreement entered into on April 4, 2005 between the Utility and the CPUC’s Office of Ratepayer Advocates, or the ORA. The settlement agreement proposes the resolution of the Utility’s claims that have been pending for several years for shareholder incentives earned by the Utility for the successful implementation of demand-side management, energy efficiency, and low-income energy efficiency programs for past program years 1994 through 2001. The Utility’s claims for shareholder incentives are addressed in the Utility’s Annual Earnings Assessment Proceeding, or AEAP. In addition to resolving claims made in the pending AEAPs, the settlement agreement proposes to resolve all future claims for shareholder incentives relating to past program years that the Utility would otherwise have made in future AEAPs through 2010.

The Utility’s total current and future shareholder incentive claims aggregate to approximately $207 million. Under the settlement agreement, the parties have agreed that the results to date show that the energy savings anticipated in the Utility’s shareholder incentive claims are being realized. The parties have proposed that the Utility receive shareholder incentives of approximately $186 million to resolve the Utility’s claims in the pending and future AEAPs. The parties have proposed that approximately $160 million be collected from electric customers and approximately $26 million be collected from gas customers, in proportion to the relative allocations of the original claims.

PG&E Corporation and the Utility cannot predict whether or when the CPUC will approve the settlement agreement. Assuming the CPUC approves the settlement agreement, the Utility would record pre-tax income of approximately $186 million during the quarter in which the settlement agreement is approved by the CPUC.

Pending CPUC Investigations

On March 17, 2005, the CPUC issued an order that institutes an investigation into the circumstances surrounding a fire that occurred at the Utility’s Mission Street substation in San Francisco in December 2003 and the ensuing power outage. Approximately 100,000 of the Utility’s customers were affected by the outage, which began in the early evening of December 20, 2003. While most customers had their power restored by the next morning, the outage lasted more than 24 hours for some customers. The CPUC’s order notes that the CPUC has authority to impose penalties in the amount of $500 to $20,000 per day per offense for violations of the Public Utilities Code. The order states that the CPUC may consider a penalty for each customer that lost power, or for each day the outage was ongoing.

In addition, the CPUC issued a press release noting that CPUC staff also would investigate the causes of a fire and power outage that originated at the Mission Street substation on March 26, 2005, that affected approximately 23,500 of the Utility’s customers.

The CPUC’s Consumer Protection and Safety Division, or CPSD, will make a penalty recommendation in July 2005. A final decision on the investigation is expected during the fourth quarter of 2005. PG&E Corporation and the Utility are unable to predict whether the outcome of this matter will have a material adverse effect on their results of operation or financial condition.

The CPUC also is conducting an investigation into the Utility’s billing and collection practices that has been opened at the request of The Utility Reform Network, or TURN. Although a definitive schedule has not yet been set, on March 22,

2005, the CPUC administrative law judge presiding over the investigation considered a schedule that contemplated the following:

September 22, 2005		Reports due from the CPSD, TURN, and other parties

December 20, 2005		Utility’s response to reports due

Late January - early February 2006		Parties file reply comments to the Utility’s response

April - May 2006		Hearings

If the CPUC finds that the Utility violated applicable tariffs or the CPUC’s orders or rules, the CPUC may impose penalties on the Utility or order the Utility to refund any amounts collected in violation of tariffs, plus interest, to customers who paid such amounts. PG&E Corporation and the Utility continue to believe that the ultimate outcome of this matter will not have a material adverse effect on PG&E Corporation’s or the Utility’s results of operations or financial condition.

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations, financing arrangements, the marketplace for electricity, natural gas, electricity transmission, natural gas transportation and storage, other goods and services, and other aspects of their business. PG&E Corporation and the Utility categorize market risks as price risk, interest rate risk and credit risk. The Utility actively manages market risks through risk management programs that are designed to support business objectives, reduce costs, discourage unauthorized risk-taking, reduce earnings volatility and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of energy and financial instruments, including forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases.

The Utility estimates fair value of derivative instruments using the midpoint of quoted bid and asked forward prices, including quotes from customers, brokers, electronic exchanges and public indices, supplemented by online price information from news services. When market data is not available, the Utility uses models to estimate fair value.

Price Risk

Convertible Subordinated Notes

In accordance with SFAS No. 133. “Accounting for Derivative Instruments and Hedging Activities,” or SFAS No. 133, the dividend participation rights component is considered to be an embedded derivative instrument and, therefore, must be bifurcated from the Convertible Subordinated Notes and marked to market on PG&E Corporation’s Consolidated Statements of Income as a non-operating expense (in Other expense, net), and reflected at fair value on PG&E Corporation’s Consolidated Balance Sheet at March 31, 2005. At March 31, 2005, the total estimated fair value of the dividend participation rights component, on a pre-tax basis, was approximately $92 million of which $20 million is classified as a current liability (in Current liabilities-Other) and $72 million is classified as a noncurrent liability (in Noncurrent liabilities-Other). The change in mark to market fair value for the quarter ended March 31, 2005, was immaterial, and approximately $32 million, pre-tax, for the quarter ended March 31, 2004.

Electricity

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

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

•	Periodic expirations of existing electricity purchase contracts, or entering into new electricity purchase contracts;

•	Fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract;

•	Changes in the Utility’s customers’ electricity demands due to customer and economic growth and weather, and implementation of new energy efficiency and demand response programs, community choice aggregation, and a core/noncore retail market structure;

•	Planning reserve and operating requirements;

•	The reallocation of the DWR power purchase contracts among California investor-owned electric utilities; and

•	The acquisition, retirement or closure of Utility generation facilities.

In addition, unexpected outages at the Utility’s generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility’s residual net open position. The Utility expects to satisfy at least some of the residual net open position through new contracts. In December 2004, the CPUC approved, with certain modifications, the Utility’s long-term electricity procurement plan, or LTPP, for the 2005 through 2014 period. The LTPP is detailed in the “Regulatory Matters” section of the MD&A in PG&E Corporation’s and the Utility’s combined 2004 Annual Report.

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

Nuclear Fuel

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

Nuclear fuel purchases are subject to tariffs of up to 8% on imports from certain countries. In the past, the Utility’s long-term nuclear fuel contracts were not subject to these tariffs. However, these contracts expired at the end of 2004, and prices under existing and future contracts may be higher as a result of such tariffs. In addition, because of an increase in U.S. demand for uranium compared with the domestic supply, uranium prices have been trending higher in 2005. During the quarter ended March 31, 2005, the Utility did not enter into any nuclear fuel purchase agreements.

As the Utility replaces contracts that expired at the end of 2004 with new higher priced uranium contracts, nuclear fuel costs will rise. The Utility is expected to partially offset these higher prices by executing a portfolio of near- and long-term contracts for nuclear fuel components. These costs are recovered in ERRA (see the “Electricity Generation Resources” section of this MD&A), therefore, the changes in nuclear fuel prices are not expected to materially impact net income.

Natural Gas

The Utility generally enters into physical and financial natural gas commodity contracts from one to 30 months in length to fulfill the needs of its retail core customers. Changes in temperature cause natural gas demand to vary daily, monthly and seasonally. Consequently, significant volumes of gas may be purchased in the monthly and, to a lesser extent, daily spot market. The Utility’s cost of natural gas purchased for its core customers includes the commodity cost, the cost of Canadian and interstate transportation and gas storage costs.

Under the Core Procurement Incentive Mechanism, or CPIM, the Utility’s purchase costs for a fixed twelve-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility’s customers receive, in their rates, three-fourths of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. While this cost recovery mechanism remains in place, changes in the price of natural gas are not expected to materially impact net income.

Transportation and Storage

The Utility currently faces price and volumetric risk for the portion of intrastate natural gas transportation capacity that is not contracted under fixed reservation charges used by core customers. Non-core customers contract with the Utility for natural gas transportation and storage, along with natural gas parking and lending (market center) services. The Utility is at risk for any natural gas transportation and storage revenue volatility. Transportation is sold at competitive market-based rates within a cost-of-service tariff framework. There are significant seasonal and annual variations in the demand for natural gas transportation and storage services. The Utility sells most of its pipeline capacity based on the volume of natural gas that is transported by its customers. As a result, the Utility’s natural gas transportation revenues fluctuate.

The Utility uses value-at-risk to measure the Utility’s exposure to market conditions that could impact transportation and storage revenues based on changes in market prices and demand for pipeline and storage services over a rolling 12-month holding period. This calculation is based on a 99% confidence level, which means that there is a 1% probability that the impact to revenues will be at least as large as the reported value-at-risk. The Utility’s value-at-risk calculated under this methodology was approximately $35 million at March 31, 2005. The Utility’s high, low, and average value-at-risk during the three months ended March 31, 2005 were approximately $43 million, $34 million and $38 million, respectively. Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, inadequate indication of the exposure of a portfolio to extreme price movements and not capturing the intra-day risk related to position changes.

Beginning January 1, 2005, the Utility began calculating value-at-risk using the methodology described above on a prospective basis only. For comparative purposes in 2005, the Utility will continue to report value-at-risk for the transportation and storage portfolio under the methodology formerly used in addition to value-at-risk calculated under the enhanced methodology.

Prior to January 1, 2005, the Utility used value-at-risk to measure the expected maximum change over a one-day period in the rolling 18-month forward value of its transportation and storage portfolio. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the portfolio will incur a 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% probability that the value of the portfolio resulting from a one-day price movement would not decline by more than $5 million. This value-at-risk methodology provides an indication of the Utility’s exposure to potential market conditions that could impact revenues based on one-day price changes. It is also a way to measure the effectiveness of hedge strategies on a portfolio.

The Utility’s value-at-risk for its transportation and storage portfolio calculated under the methodology used prior to January 1, 2005 was approximately $2 million at March 31, 2005 and approximately $3 million at March 31, 2004. A comparison of daily values-at-risk is included in order to provide context around the one-day amounts. The Utility’s high, low and average transportation and storage value-at-risk during the three months ended March 31, 2005 were approximately $4 million, $2 million and $2 million, respectively. The Utility’s high, low and average transportation and storage value-at-risk during the three months ended March 31, 2004 were approximately $6 million, $3 million and $4 million, respectively.

Value-at-risk calculated under the methodology used prior to January 1, 2005 has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, mismatch of one-day liquidation period assumed in the value-at-risk methodology as compared to the longer term holding period of the storage and transportation portfolio, and inadequate indication of the exposure of a portfolio to extreme price

movements. In addition, this value-at-risk methodology does not measure intra-day risk from position changes nor does it measure volumetric uncertainty in the demand for pipeline services.

Due to the limitations of this value-at-risk methodology, the Utility enhanced the calculation methodology as described above to 1) capture uncertainty with respect to demand (volumetric uncertainty) for pipeline services, 2) reflect the market conditions in which the pipeline operates by increasing the holding period to 12 months, and 3) include the uncertainty associated with the option exposure in the pipeline portfolio.

Interest Rate Risk

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

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At March 31, 2005, if interest rates changed by 1% for all current variable rate debt issued by PG&E Corporation and the Utility, the change would affect net income by an immaterial amount, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

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

PG&E Corporation had gross accounts receivable of approximately $2.0 billion at March 31, 2005 and approximately $2.2 billion at December 31, 2004. The majority of the accounts receivable were associated with the Utility’s residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately $88 million at March 31, 2005 and approximately $93 million at December 31, 2004 were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not considered likely.

The Utility manages credit risk for its wholesale customers and counterparties by assigning credit limits based on an evaluation of their financial condition, net worth, credit rating and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure for the Utility’s wholesale customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure or obtain additional collateral, or both. Further, the Utility relies heavily on master agreements that require security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

The Utility calculates gross credit exposure for each of its wholesale customers and counterparties as the current mark-to-market value of the contract (i.e., the amount that would be lost if the counterparty defaulted today), plus or minus any outstanding net receivables or payables, before the application of credit collateral. During the three months ended March 31, 2005, the Utility recognized no material losses due to contract defaults or bankruptcies. At March 31, 2005, there were two counterparties that represented greater than 10% of the Utility’s net wholesale credit exposure. Both of these counterparties were investment grade, representing a total of approximately 47% of the Utility’s net wholesale credit exposure.

The Utility conducts business with wholesale counterparties mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. This concentration of counterparties may impact the Utility’s overall exposure to credit risk because counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions. Credit losses experienced as a result of electrical and gas procurement activities are expected to be recoverable from customers and are therefore, not expected to have a material impact on earnings.

CRITICAL ACCOUNTING POLICIES

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

Regulatory Assets and Liabilities

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the cost of providing service. SFAS No. 71 applies to all of the Utility’s operations except for the operations of a natural gas pipeline. During the first quarter of 2004, the Utility began reapplying SFAS No. 71 to its generation operations.

Under SFAS No. 71, regulatory assets represent capitalized costs that otherwise would be charged to expense under GAAP. These costs are later recovered through regulated rates. Regulatory liabilities are created by rate actions of a regulator that will later be credited to customers through the ratemaking process. Regulatory assets and liabilities are recorded when it is probable, as defined in SFAS No. 5, “Accounting for Contingencies,” or SFAS No. 5, that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, CPUC and FERC administrative law judge proposed decisions, final regulatory orders and the strength or status of applications for regulatory rehearings or state court appeals. The Utility also maintains regulatory balancing accounts, which are comprised of sales and cost balancing accounts. These balancing accounts are used to record the differences between revenues and costs that can be recovered through rates.

If the Utility determined that it could not apply SFAS No. 71 to its operations or, if under SFAS No. 71 it could not conclude that it is probable that revenues or costs would be recovered or reflected in future rates, the revenues or costs would be charged to income in the period in which they were incurred. If it is determined that a regulatory asset is no longer probable of recovery in rates, then SFAS No. 71 requires that it be written off at that time. At March 31, 2005, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of approximately $7.4 billion and regulatory liabilities (including current balancing accounts payable) of approximately $4.5 billion.

Unbilled Revenues

The Utility records revenue as electricity and natural gas are delivered. A portion of the revenue recognized has not yet been billed. Unbilled revenues are determined by factoring an estimate of the electricity and natural gas load delivered with recent historical usage and rate patterns. At March 31, 2005, the Utility had recorded approximately $500 million in unbilled revenues.

Environmental Remediation Liabilities

Given the complexities of the legal and regulatory environment regarding environmental laws, the process of estimating environmental remediation liabilities is a subjective one. The Utility records a liability associated with environmental remediation activities when it is determined that remediation is probable, as defined in SFAS No. 5, and the cost can be estimated in a reasonable manner. The liability can be based on many factors, including site investigations, remediation, operations, maintenance, monitoring and closure. This liability is recorded at the lower range of estimated costs, unless a more objective estimate can be achieved. The recorded liability is re-examined every quarter.

At March 31, 2005, the Utility’s accrual for undiscounted environmental liability was approximately $408 million. The Utility’s undiscounted future costs could increase to as much as $571 million if other potentially responsible parties are not able to contribute to the settlement of these costs or the extent of contamination or necessary remediation is greater than anticipated.

Asset Retirement Obligations

The Utility accounts for its nuclear generation and certain fossil generation facilities under SFAS No. 143, “Accounting for Asset Retirement Obligations,” or SFAS No. 143. 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. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and costs recovered through the ratemaking process.

There are uncertainties regarding the ultimate cost associated with retiring the assets the Utility has accounted for in accordance with SFAS No. 143. These include, but are not limited to changes in assumed dates of decommissioning, regulatory requirements, technology, cost of labor, materials, and equipment. At March 31, 2005, the Utility’s estimated cost of retiring these assets was approximately $1.3 billion.

Pension and Other Postretirement Plans

Certain employees and retirees of PG&E Corporation and its subsidiaries participate in qualified and non-qualified non-contributory defined benefit pension plans. Certain retired employees and their eligible dependents of PG&E Corporation and its subsidiaries also participate in contributory medical plans, and certain retired employees participate in life insurance plans (referred to collectively as other benefits). Amounts that PG&E Corporation and the Utility recognize as costs and obligations to provide pension benefits under SFAS No. 87, “Employers’ Accounting for Pensions,” and other benefits under SFAS No. 106, “Employers Accounting for Postretirement Benefits other than Pensions,” are based on a variety of factors. These factors include the provisions of the plans, employee demographics and various actuarial calculations, assumptions and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations and the importance of the assumptions utilized, PG&E Corporation’s and the Utility’s estimate of these costs and obligations is a critical accounting estimate.

In accordance with accounting rules, changes in benefit obligations associated with these assumptions may not be recognized as costs on the income statement. Differences between actuarial assumptions and actual plan results are deferred and are amortized into cost only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-value of the related plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. As such, significant portions of benefit costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants. Under SFAS No. 71, regulatory adjustments have been recorded in the Consolidated Statements of Income and Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach. The CPUC has authorized the Utility to recover the costs associated with its other benefits for 1993 and beyond. Recovery is based on the lesser of the amounts collected in rates or the annual contributions on a tax-deductible basis to the appropriate trusts.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Refer to Note 1 in the Notes to the Condensed Consolidated Financial Statements for further discussion.

TAXATION MATTERS

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

At a case management conference held on March 18, 2005, the San Francisco Superior Court, or Superior Court, issued its final ruling on rejecting the “per victim” and “per [customer] bill” standards advocated by the plaintiffs to be applied in calculating the number of alleged violations of California Business and Professions Code Section 17200, or Section 17200. The Superior Court found that the appropriate standard to be applied was the “per act” test, and that the acts alleged to violate Section 17200 are “transfers of assets to [PG&E Corporation] from its utility subsidiary.” Such asset transfers were effected primarily through the Utility’s payment of dividends to PG&E Corporation and through share repurchases from the date of PG&E Corporation’s formation on January 1, 1997, through the end of 2000, when dividends were last paid.

Also on March 18, the Superior Court ordered plaintiffs to provide a list of the transfers that they claim are unlawful, as well as the basis for their claim with respect to each transfer, at the next case management conference scheduled for May 10, 2005.

For more information regarding these cases, see “Part I, Item 3: Legal Proceedings” of PG&E Corporation’s and the Utility’s combined 2004 Annual Report on Form 10-K.

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

As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002, PG&E Corporation issued warrants to purchase 5,066,931 shares of common stock of PG&E Corporation at an exercise price of $0.01 per share. During the quarter ended March 31, 2005, warrant holders exercised, on a net exercise basis, warrants to purchase 77,857 shares, and received 77,833 shares of PG&E Corporation common stock. As of March 31, 2005, warrant holders had exercised, on a net exercise basis, warrants to purchase 4,796,876 shares, and had received 4,795,123 shares of PG&E Corporation common stock since the warrants were issued.

Pacific Gas and Electric Company did not make any sales of unregistered equity securities during the quarter ended March 31, 2005, the period covered by this report.

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased			Average Price Paid Per Share				Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2)(3)		Approximate Dollar Value of Shares that may yet be Purchased Under the Plans or Programs
	Preferred Stock		Common Stock	Preferred Stock		Common Stock		Preferred Stock	Common Stock	Preferred Stock	Common Stock

January 1 through January 31, 2005	125,000	(1)	—	$	25.39375	—		—	—	—	$	975,000,000
February 1 through February 28, 2005	—		—	—		—		—	—	—	1,050,000,000
March 1 through March 31, 2005	—		29,489,400	—		$	35.60	—	29,489,400	—	—
Total	125,000		29,489,400	$	25.39375	$	35.60	—	29,489,400	—	—

(1) On January 31, 2005, pursuant to a mandatory sinking fund redemption provision, the Utility redeemed 125,000 shares of its 6.30% Series of First Preferred Stock. The redemption price includes any accumulated and unpaid dividends existing as of the redemption date.

(2) On September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase shares of PG&E Corporation’s common stock with an aggregate purchase price not to exceed PG&E Corporation’s net cash proceeds from sales of PG&E Corporation’s common stock upon exercise of options granted under PG&E Corporation’s Stock Option Plan. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Repurchases may be made from time until the program expires on December 31, 2005. Amounts remaining under this program are not determinable as PG&E Corporation cannot predict how many options will be exercised before December 31, 2005.

(3) On December 15, 2004, PG&E Corporation’s Board of Directors authorized the repurchase of up to $975 million of its outstanding common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on December 16, 2004. On February 16, 2005, the Board of Directors of PG&E Corporation increased the repurchase authorization to $1.05 billion with such repurchases to be effected from time to time, but no later than June 30, 2006. As disclosed in a Form 8-K filed on March 4, 2005, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on March 4, 2005, under which PG&E Corporation repurchased 29,489,400 shares for an aggregate purchase price of approximately $1.05 billion. For further information, see the “Liquidity and Financial Resources” section included in Part I, Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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

PG&E Corporation:

On April 20, 2005, PG&E Corporation held its annual meeting of shareholders. At the meeting, the shareholders voted as indicated below on the following matters:

1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors are elected and qualified (included as Item 1 in the proxy statement):

	For	Withheld

David R. Andrews	299,848,011	7,547,101
Leslie S. Biller	299,930,742	7,464,370
David A. Coulter	230,734,940	76,660,172
C. Lee Cox	298,746,220	8,648,892
Peter A. Darbee	299,920,605	7,474,507
Robert D. Glynn, Jr.	297,333,005	10,062,107
Mary S. Metz	299,595,454	7,799,658
Barbara L. Rambo	298,729,457	8,665,655
Barry Lawson Williams	297,680,081	9,715,031

2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2005 (included as Item 2 in the proxy statement):

For:		301,591,184
Against:		2,895,809
Abstain:		2,908,119

This proposal was approved by a majority of the shares represented and voting (including abstentions) with respect to this proposal, which shares voting affirmatively also constituted a majority of the required quorum.

3. Consideration of management’s proposal regarding the adoption of a new long-term incentive plan (included as Item 3 in the proxy statement):

For:		222,208,088
Against:		33,828,404
Abstain:		4,284,940
Broker non-vote (1):		47,073,680

This management proposal was approved by a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to the proposal, which shares voting affirmatively also constituted a majority of the required quorum.

4. Consideration of a shareholder proposal regarding the expensing of stock options (included as Item 4 in the proxy statement):

For:		114,642,888
Against:		138,186,945

Abstain:		7,491,599
Broker non-vote (1):		47,073,680

This shareholder proposal was not approved, as the number of shares voting affirmatively on the proposal constituted less than a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to the proposal.

5. Consideration of a shareholder proposal regarding radioactive wastes (included as Item 5 in the proxy statement):

For:		9,194,928
Against:		225,080,468
Abstain:		26,046,036
Broker non-vote (1):		47,073,680

6. Consideration of a shareholder proposal regarding poison pills (included as Item 6 in the proxy statement):

For:		73,493,699
Against:		180,191,178
Abstain:		6,636,555
Broker non-vote (1):		47,073,680

7. Consideration of a shareholder proposal regarding performance-based options (included as Item 7 in the proxy statement):

For:		99,406,293
Against:		154,791,718
Abstain:		6,123,421
Broker non-vote (1):		47,073,680

8. Consideration of a shareholder proposal regarding future golden parachutes (included as Item 8 in the proxy statement):

For:		142,467,316
Against:		113,113,566
Abstain:		4,740,550
Broker non-vote (1):		47,073,680

This shareholder proposal was approved by a majority of the shares represented and voting (including abstentions but excluding broker non-votes) with respect to the proposal, which shares voting affirmatively also constituted a majority of the required quorum.

(1)A non-vote occurs when brokers or nominees have voted on some of the matters to be acted on at a meeting, but do not vote on certain other matters because, under the rules of the New York Stock Exchange, they are not allowed to vote on those other matters without instructions from the beneficial owner of the shares. Broker non-votes are counted when determining whether the necessary quorum of shareholders is present or represented at each annual meeting.

Pacific Gas and Electric Company:

On April 20, 2005, Pacific Gas and Electric Company, or the Utility, held its annual meeting of shareholders. Shares of capital stock of Pacific Gas and Electric Company consist of shares of common stock and shares of first preferred

stock. As PG&E Corporation and a subsidiary own all of the outstanding shares of common stock, they hold approximately 95% of the combined voting power of the outstanding capital stock of the Utility. PG&E Corporation and the subsidiary voted all of their respective shares of common stock for the nominees named in the 2005 joint proxy statement and for the ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2005. The balance of the votes shown below was cast by holders of shares of first preferred stock. At the annual meeting, the shareholders voted as indicated below on the following matters:

1. Election of the following directors to serve until the next annual meeting of shareholders or until their successors are elected and qualified (included as Item 1 in the proxy statement):

	For	Withheld
David R. Andrews	335,101,496	134,171
Leslie S. Biller	335,093,610	142,057
David A. Coulter	334,812,805	422,862
C. Lee Cox	335,097,258	138,409
Peter A. Darbee	335,098,109	137,558
Robert D. Glynn, Jr.	335,092,033	143,634
Mary S. Metz	335,086,883	148,784
Barbara L. Rambo	335,087,579	148,088
Gordon R. Smith	335,098,589	137,078
Barry Lawson Williams	335,090,698	144,969

2. Ratification of the appointment of Deloitte & Touche LLP as independent public accountants for 2005 (included as Item 2 in the proxy statement):

For:		335,126,354
Against:		43,606
Abstain:		65,707

ITEM 5. OTHER INFORMATION

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

Pacific Gas and Electric Company, or the Utility’s, earnings to fixed charges ratio for the three months ended March 31, 2005, was 3.27. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2005, was 3.09. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into the Utility’s Registration Statement Nos. 33-62488 and 333-109994 relating to various series of the Utility’s first preferred stock and its senior secured bonds, respectively.

ITEM 6. EXHIBITS

4.1		Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A.
10.1		Master Confirmation dated March 4, 2005, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.2		First Amendment, dated as of April 8, 2005, to the Credit Agreement dated as of December 10, 2004 (previously filed with PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99), among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent and a lender, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as

PART I.	FINANCIAL INFORMATION
ITEM 1.	CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
		Condensed Consolidated Statements of Income		3
		Condensed Consolidated Balance Sheets		4
		Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		7
		Condensed Consolidated Balance Sheets		8
		Condensed Consolidated Statements of Cash Flows		10
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		General	11
	NOTE 2:		The Utility’s Emergence from Chapter 11	20
	NOTE 3:		Debt	21
	NOTE 4:		Energy Recovery Bonds	26
	NOTE 5:		Shareholders’ Equity	26
	NOTE 6:		Risk Management Activities	28
	NOTE 7:		Commitments and Contingencies	29
	NOTE 8:		Subsequent Events	36

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			37
	Results of Operations			42
	Liquidity and Financial Resources			47
	Contractual Commitments			52
	Capital Expenditures			53
	Off-Balance Sheet Arrangements			53
	Contingencies			53
	Risk Management Activities			56
	Critical Accounting Policies			60
	Accounting Pronouncements Issued But Not Yet Adopted			61
	Taxation Matters			61
	Additional Security Measures			62
	Environmental and Legal Matters			62

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			62
ITEM 4.	CONTROLS AND PROCEDURES			62

PART II.	OTHER INFORMATION			64

ITEM 1.	LEGAL PROCEEDINGS			64
ITEM 2.	CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES			65
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			66
ITEM 5.	OTHER INFORMATION			68
ITEM 6.	EXHIBITS			68

SIGNATURES				70

		regulations and policies; and

•		The outcome of pending litigation.

•		Increased competition as a result of the takeover by condemnation of the Utility’s distribution assets, duplication of the Utility’s distribution assets or service by local public utilities, and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and

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

		documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, KBC Bank N.V., and The Bank of New York
10.3		Credit Agreement dated as of April 8, 2005, among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JP Morgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC, BNP Paribas and Deutsche Bank Securities Inc., as documentation agents and lenders, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, The Bank of Nova Scotia, UBS Loan Finance LLC, and Union Bank of California, N.A., as senior managing agents, and KBC Bank, NV, Morgan Stanley Bank and William Street Commitment Corporation, as lenders
10.4*		PG&E Corporation 2006 Long-Term Incentive Plan, effective as of January 1, 2006 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 8-K filed April 25, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
11		Computation of Earnings Per Common Share
12.1		Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2		Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
31.1		Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
32.1**		Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
32.2**		Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

	PG&E CORPORATION

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


	PACIFIC GAS AND ELECTRIC COMPANY

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

NOTE 2: THE UTILITY’S EMERGENCE FROM CHAPTER 11

Utility

NOTE 4: ENERGY RECOVERY BONDS

Stock Repurchases

Dividends

NOTE 6: RISK MANAGEMENT ACTIVITIES

Non-Trading Activities

NOTE 7: COMMITMENTS AND CONTINGENCIES

Reliability Must Run Agreements

PG&E Corporation

FERC Proceedings

Mirant Settlement

Legal Matters

NOTE 8: SUBSEQUENT EVENTS

OVERVIEW

Factors Affecting First Quarter 2005 Results of Operation and Financial Condition

Issuance of Energy Recovery Bonds

Stock Repurchases and Dividends

Credit Rating Upgrades

FORWARD-LOOKING STATEMENTS

Appeals of the Utility’s Plan of Reorganization and Settlement Agreement

Operating Environment

Legislative and Regulatory Environment and Pending Litigation

Competition and Bypass

RESULTS OF OPERATIONS

LIQUIDITY AND FINANCIAL RESOURCES

Overview

Liquidity

PG&E Corporation and the Utility intend to retain sufficient cash for operating needs and to manage debt levels to maintain access to credit. PG&E Corporation and the Utility target cash balances, which, together with credit facilities, accommodate normal and unforeseen demands on its liquidity.

Dividends

Utility

CONTRACTUAL COMMITMENTS

Utility

OFF-BALANCE SHEET ARRANGEMENTS

CONTINGENCIES

Regulatory Matters

Electricity Generation Resources

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

RISK MANAGEMENT ACTIVITIES

Convertible Subordinated Notes

Transportation and Storage

Credit Risk

Regulatory Assets and Liabilities

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

TAXATION MATTERS

ADDITIONAL SECURITY MEASURES

ENVIRONMENTAL AND LEGAL MATTERS

ITEM 3: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4. CONTROLS AND PROCEDURES

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

ITEM 5. OTHER INFORMATION

ITEM 6. EXHIBITS

SIGNATURES

EXHIBIT INDEX